Text

Licensee Guarantees of Payment of Deferred Premiums
	ML18206A463
Person / Time
Site:	Cooper
Issue date:	07/17/2018
From:	Shaw J; Nebraska Public Power District (NPPD)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NLS2018037
	Download: ML18206A463 (62)
	v • d • e

r H

Nebraska Public Power District Always there w hen you need us NLS2018037 140.21 July 17, 2018 Attention: Document Control Desk Director, Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001

Subject:

Licensee Guarantees of Payment of Deferred Premiums Cooper Nuclear Station, Docket No. 50-298, DPR-46

Dear Sir or Madam:

The purpose of this letter is to transmit information in accordance with the requirements of 10 CFR Part 140.21 , relative to deferred insurance premiums, for the Nebraska Public Power District (NPPD). NPPD believes this information demonstrates our ability to obtain funds in the amount of $19 .0 million for payment of such premiums within the specified three-month period.

To demonstrate the ability to provide funds in the required amount for such deferred insurance premiums, NPPD' s 2017 Financial Report is enclosed for your review. This report is NPPD ' s audited financial statement. Please refer to Page 29 of the enclosure where the Balance Sheet of NPPD is listed. Cash and investments of NPPD total over $1.3 billion as indicated on Page 37, Note 2 of the enclosure. Liquidity can be provided by unrestricted cash and investments, and through reserve and special purpose funds that, with the approval of the NPPD Board of Directors, can be utilized for any lawful purpose. The portion of cash and investments that can be utilized to provide such liquidity for the payment of the subject deferred premiums is $618.0 million as of December 31 , 2017.

Also on Page 29 of the enclosure, under the heading "Current Liabilities," there is a line item titled "Notes and credit agreements, current" in the amount of $165.2 million, and under the heading "Long-Term Debt," there is a line item titled "Notes and credit agreements, net of current" in the amount of $69.0 million. As noted on Pages 42-44, Note 7, "Tax-Exempt Revolving Credit Agreement" and "Taxable Revolving Credit Agreement" of the enclosure, NPPD is authorized to issue up to $150 million of the Tax-Exempt Revolving Credit Agreement (TERCA), and an aggregate of $200 million of the Taxable Revolving Credit Agreement (TRCA). As of December 31 , 2017, NPPD had $81.0 million remaining capacity in its TERCA program, and $34.8 million remaining capacity of the TRCA, for a total of $115.8 million, which is available to fund the payment of the subject deferred premiums.

COOPER NU CLEAR STATION P.O. Box 98 / Brownvi lle, NE 68321-0098 Telephone: (402) 825-3811 / Fax: (402) 825-5211 www.nppd.com

NLS2018037 Page 2 of2 It is NPPD ' s intent to continue to publish this report on an annual calendar year basis. A subsequent report, covering financial information for calendar year 2018, will be submitted no later than July 31, 2019.

This letter contains no new commitments.

Should you have questions or require additional information, please contact me at 402-825-2788.

Sincerely, Licensing Manager ljo

Enclosure:

Nebraska Public Power District 2017 Financial Report cc: Regional Administrator w/enclosure USNRC - Region IV Cooper Project Manager w/enclosure USNRC - NRR Plant Licensing Branch IV Senior Resident Inspector w/o enclosure USNRC - CNS NPG Distribution w/o enclosure D. K. Starzec w/o enclosure CNS Records w/enclosure

r NLS2018037 Enclosure ENCLOSURE NEBRASKA PUBLIC POWER DISTRICT 2017 FINANCIAL REPORT COOPER NUCLEAR ST ATION DOCKET NO. 50-298, DPR-46

Statistical Review (Unaudited) 11 Management's Discussion and Analysis (Unaudited) 12 Report of Independent Auditors 28 Financial Statements 29 Notes to Financial Statements 32 Supplemental Schedules (Unaudited) 65 2017 YEAR AT A GLANCE KlllLJOWAifT - HOl!JR SALES 119.6 Bll.UION OA8RA1mNG RE~ENllJES $ ;3101 6 Ml UtO:N cosr OXF ~O>W8R P!!J'RGH~S8Cl>tA1ND S8NSRAifiE[l) S6.I MIU ION 01rH;8R CilAERA1rllfNG E~Pt8 ~S:8S 11;2 8 M IULllO~

N\~SmNIENr ~m omHl!ER INO::GME $ 216 MI LIION D8BT AKD O>illt,IER E>~AENS!BS 6S:0 MIUUIOlN LNCRE~SE 1,N NiEJ P~SlllilO>N $ rn .cS NIH.JL[Cil DEBTSE!il_WQEG0~8~GE 2.11 1JjJMES Fililamrcfa~!l&epont 10

2017 STATISTICAL REVIEW (Unaudited)

Average Cents Per kWh Sold Average Average Less Government Cents Per Number of MI/Vh Re\Enues (in OOO's)

OPERATING REVENUES TaxesfTransfers " kWh Sold Customers Amount % Amount %

Retail:

Residential ... ..... ... ... ... ...... 10.72 ¢ 12.74 ¢ 72,021 809,095 4.1 $ 103,101 9.4 Commercial ..... ... ..... ....... .. 8.46 ¢ 9.86 ¢ 19,533 1,125,311 5.8 110,906 10.1 Industrial .... ....... .. .... ..... .... 5.22 ¢ 5.57 ¢ 60 1,314,989 6.7 73,244 6.6 Total Retail Sales ... .. .. ..... 7.71 ¢ 8.84 ¢ 91 ,614 3,249,395 16.6 287,251 26.1 Wholesale:

Municipalitiesw .... ...... .. .. .......... .... ... .... ...... 6.33 ¢ 45 1,658,984 8.5 104,985 9.5 Municipalities (Partial Requirements)c,i .... .... 5.77 ¢ 186,956 0.9 10,785 0.9 Public Pov.er Districts and Cooperati'.Esc21 . . 5.93 ¢ 25 7,966,644 40.7 472,291 42.9 Total Firm Wholesale Sales .... ... .... .... ... ... . 5.99 ¢ 71 9,812,584 50.1 588,061 53.3 Total Firm Retail and Wholesale Sales .... 6.70 ¢ 91 ,685 13,061 ,979 66.7 875,312 79.4 Participation Sales ...... ................ .. ....... .... ....... 3.71 ¢ 5 1,973,441 10.1 73,199 6.6 OtherSalesc*1 . . ... . ... . . . . .. . . ... . .. . . .. . . . . . . . .. . . . . . .. .. . . .. 2.48 ¢ 2 4 ,533,128 23.2 112,209 10.2 Total Electric Energy Sales ......... .. ... ... ... 5.42 ¢ 91 1692 191568,548 100.0 1,060,720 96.2 Other Operating RevenuesCsJ .... ... ... .... ............ ..... ... .... ...... .. ..... ..... ......... ... .. ... ....... .. ..... ......... ..... ...... .. . . 76,182 6.9 Unearned Revenuesc61 . ... . . . . ... . . . . . . ... .. . .. .... . . . ... ... ... .. . . .. .. . .. . ... . . . ... ... . . . . . .. . . . . . . .... . . .. . . .. . . .. . . . . . .. . .. . . .. .... .. . ... . . (35,260) (3.1)

Total Operating Re\Enues ... .... ... .......... ........ .... .......... .... .... .. .................... ..... ....... .. ... ..... .... .......... .... .. .. . $1,101,642 100.0 MI/Vh Costs (in OOO's)

COST OF POWER PURCHASED AND GENERATED Amount % Amount %

Productionc,i .......... ... ... ....... ........ ..... ...... .. ....... .... ..... ......... ..... .. ... ...... ...... .. .. 15,850,887 77.9 $ 424,190 72.4 Power Purchased* **** ***** **** ***** ** **** ******** ***** *** ** ******* ********** ****-*** *- *****-** **-*****-

4,501 ,041 22.1 161,963 27.6 Total Production and Power Purchased ......... ........ .... .............. ... ............. . 20,35\928 100.0 $ 586, 153 100.0 CONTRACruAL AND TAX PAYMENlS (in OOO's) <*1 Amount Payments to Retail ConTnunities ......... ... ...... .. ...... ..... ... ..... ......... .. ... .. ........ .. ............... ... ... .. ... ...... .... .. .. $ 27, 102 Payments in Lieu of T.vces ................ ......... ............... ................ .. ............. .. .......... ................... ......... . 10,060 Total Contractual and Tax Payments .. ...................... ...................... .. ..... ........................................ . i 37,162 OllER Amount Miles of Transmission and Subtransmission lines in SeNce ........................... ................................ ... . 5,294 NuniJer of Ful-lilTle Enl:>k>yees .... .... ... ....... .................................... ......................................... ........... 1,875

( 1) Customer oollections for laxesllransfers to other governments are excluded from base rates.

(2) Sales are total requirements. subject to certain exceptions.

(3) Sales are to a customer who limited !heir requirements under the 2002 Contract. The average rate was lower than total requirements cuslomefS due to lhe exclusion of certain transmission costs fiom the wholesale rate as cost recovery was through the SPP transmission tariff. These revenues were induded in Other Sales.

(4) lndudes sales in the Southwest Power Pool r sPP"') and nonfirm sales to olher utilities.

(5) lndudes revenues for transmission and other miscelaneous revenues.

(6) lndudes unearned revenues fiom prior periods of S6.7 milion, recogllized revenues of $23.0 milion for other postemployment benefit f OPEB'l expenses related to past service and included in 2017 rates, 2017 surplus revenues d eferred to future periods of $44.9 milion and collections of $20.0 milion for lhe 201 8 Cooper Nuclear Stalioo ("CNSm) refueling and maintenance outage.

(7) lndllldes fuel, operation, and maintenance costs. Debt senrioe and capilal-relateli oosls are excluded_

SOURCES OF THE DISTRICT'S ENERGY SUPPLY

(%0FIIWH)

This chart shows the sources of energy for Hydro sales, exduding participation sales to other 6.3%

utilities. Purchases were induded in the appropriate source, except for those purchases Purchases for which the source was not known. 4.1%

1.5%

45.3%

Ffarnncial IR!e:F>(!ll1t

MANAGEMENT'S DISCUSSION AND ANALYSIS (Unaudited)

The financial report for the Nebraska Public Power District ("District") includes the Management's Discussion and Analysis , Financial Statements, Notes to Financial Statements, and Supplemental Schedules. The financial statements consist of the Balance Sheets, Statements of Revenues , Expenses, and Changes in Net Position, Statements of Cash Flows, and Supplemental Schedules.

The following Management's Discussion and Analysis ("MD&A") provides unaudited information and analyses of activities and events related to the District's financial position or results of operations. The MD&A should be read in conjunction with the audited Financial Statements and Notes to Financial Statements.

The Balance Sheets present assets, deferred outflows of resources, liabilities, deferred inflows of resources and net position as of December 31 , 2017 and 2016. The Statements of Revenues, Expenses, and Changes in Net Position present the operating results for the years 2017 and 2016. The Statements of Cash Flows present the sources and uses of cash and cash equivalents for the years 2017 and 2016. The Notes to Financial Statements are an integral part of the basic financial statements and contain information for a more complete understanding of the financial position as of December 31 , 2017 and 2016, and the results of operations for the years 2017 and 2016. The Supplemental Schedules include unaudited information required to accompany the Financial Statements.

OVERVIEW OF BUSINESS The District is a public corporation and political subdivision of the State of Nebraska (the "State"). Control of the District and its operations are vested in a Board of Directors ("Board") consisting of 11 members popularly elected from districts comprising subdivisions of the District's chartered territory.

The District's chartered territory includes all or parts of 86 of the State's 93 counties and more than 400 municipalities in the State. The right to vote for the Board is generally limited to retail and wholesale customers receiving more than 50% of their annual energy from the District.

The District operates an integrated electric utility system including facilities for generation, transmission, and distribution of electric power and energy for sales at retail and wholesale. Management and operation of the District is accomplished with a staff of approximately 1,875 full-time employees. The District has the power, among other things, to acquire, construct, and operate generating plants, transmission lines, substations, and distribution systems and to purchase, generate, distribute, transmit, and sell electric energy for all purposes.

There are no investor-owned utilities providing retail electric service in Nebraska.

The District has no power of taxation, and no governmental authority has the power to levy or collect taxes to pay, in whole or in part, any indebtedness or obligation of or incurred by the District or upon which the Disbict may be liable. The Oisbict has the right of eminent domain. The property of the Oisbict, in the opinion of its General Counsel, is exempt under the State Constitution from taxation by the State and its subdivisions, but the Disbict is required by the State to make payments in lieu of taxes which are disbibuted to the State and various governmental subdivisions.

The Oisbict has the power and is required to fix, establish, and collect adequate rates and other charges for electrical energy and any and all commodities or services sold or furnished by it. Such rates and charges must be fair, reasonable, and nondiscriminatory and adjusted in a fair and equitable manner to confer upon and disbibute among the users and consumers of sudl commodities and services the benefits of a successful and profitable operation and conduct of the business of the Disbict.

THE SYSTEM To meet the anytime peak load *n 2017 of 2,891 .5 megawatts r MW), the D"sbict had available 3,651.0 MW of capacity resouroes that included 3,046.2 MW of generation capacity hum 12 owned and operated generating plants and 22 pla ts over which lhe District has operating control, 447.6 MW of firm capacity purchases from the Fimainoiaa ~8iFJOI1t 12

Western Area Power Administration , and 157.2 MW of a capacity purchase from Omaha Public Power District's

("OPPD") Nebraska City Station Unit 2 ("NC2") coal-fired plant. Of the total capacity resources, 275.7 MW are being sold via participation sales or other capacity sales agreements, leaving 3,375.3 MW to serve firm retail and wholesale customers and to meet capacity reserve requirements. The highest summer anytime peak load of 3,030.3 MW was established in July 2012 and the highest winter anytime peak load of 2,252.0 MW was established in January 2014 for firm requirements customers.

The following table shows the District's capacity resources from generation and respective summer 2017 accredited capability.

Summer 2017 Number of Accredited Plants(1> Ca~abilify {MW} (ZJ Percent of Total Steam - Conventional C:JJ **** ****** *** . **** *** ** ******* *** *********** 3 1,679.3 55.2 Steam - Nuclear ............ ................. ... ..... ... ........ .. .. .. . . 1 765.0 25.1 Combined Cycle .. ........... ..... ... ... ...... ...... .... ... .... .. .... . . 1 220.0 7.2 Combustion Turbine C4 > .... . ........ .. .. ....* .. . . ...... ..... ... .. . ... 3 125.3 4.1 Hydro ... ............. ..... .. .... ..... ...... .. ... .... ..... ... ...... ......... . 6 106.8 3.5 Diesel ........ ... ... .. ............... .. ........ .... .... ... .. .... ... .... .... . 12 93.6 3.1 Wind CsJ ..*... ... .. .. .. .. .... . . ... *..... *... .... .. *.. . *....*.* * .... ... ..... 8 56.2 1.8 34 3,046.2 100.0 (1) lndudes three hydro plants and 12 diesel plants under contract to the District (2) 2017 summer acaedited net capability based on SPP aiteria.

(3) lndudes Gerald Gentleman Station ("GGS"), Sheldon Station ("Sheldon"), and Canaday Station.

(4) lndudes the Hallam, Hebron and McCook peaking turbines.

(5) lndudes Ainsworth Wind Energy Facility ("Ainsworth") and seven wind facilities under contract to the District.

The following table shows the generation facilities owned by the District and their respective fuel types, summer 2017 accredited capability, and in-service dates.

Surrmer 2017 Accredited 11 Type Fuel Type Capabilify (MIN) ' ln-SeNce Date Gerald Gentleman Station lhts No. 1 and No. 2 ......... . Coal 1,365.0 1979, 1982 Cooper lllJclear Station ............. ............................... . lllJclear 765.0 1974 Beamce P0111er Station ............................................. . Combined Cycle 220.0 2005 Sheldon Station l.tits No. 1 and No. 2 ....................... . Coal 215.0 1961 , 1968 Combustion Turbines (3 generating plalts) .................. . Oil or Nab.Jral Gas 125.3 1973 Canaday Station ....... ................................................ . Nab.Jral Gas 99.3 1958 Hydro (3 generating plalts) ........... ............................ . Water 21 .3 1887, 1927, 1939 Ainsworth Wind Energy Faciityu 1 ** ******** *********.********* Wind 8.3 2005 2,819.2 (1) 2017 summer accredited net capabiity based oo SPP aiteriia.

(2) Nominaly rated al 60 MW.

Fililanci:al :Rep:)(!mt

THE CUSTOMERS Retail and Wholesale Customers In 2017, the District served an average of 91 ,614 retail customers. Currently the District's retail service territory includes 79 municipal-owned distribution systems operated by the District for the municipality pursuant to a Professional Retail Operations ("PRO") Agreement. Details of the District's PRO Agreements are included in Note 12 in the Notes to Financial Statements.

The District serves its wholesale customers under total requirements contracts that require them to purchase total power and energy requirements from the District, subject to certain exceptions. In 2016, the District entered into 20-year wholesale power sales contracts with a substantial number of its wholesale customers (the "2016 Contracts"). The 2016 Contracts replaced wholesale contracts that were entered into in 2002 (the "2002 Contracts"). Wholesale customers served under the 2016 Contracts include 23 public power districts (20 of which are served under one contract with the Nebraska Generation and Transmission Cooperative) , one cooperative, and 37 municipalities. Wholesale customers served under the 2002 Contracts include one public power district and nine municipalities. The District's goal , with respect to the cost of wholesale service (production and transmission}, is that such costs are among the lowest quartile (25th percentile or less) for cost per kilowatt-hour

("kWh") purchased, as published by the National Rural Utilities Cooperative Finance Corporation Key Ratio Trend Analysis (Ratio 88) (the "CFC Data"). The District's wholesale power costs percentile was 28.2% for 2016, based on the latest available data. Details of the District's Wholesale Power Contracts are included in Note 12 in the Notes to Financial Statements.

The following charts show the District's average retail and wholesale cents per kVVh for the years ended December 31 , 2013 through 2017. The District also reported average cents per kVVh sold less customer collections for taxes and transfers to other governments, which are not induded in the District's base rates for retail customers.

AVERAGE CENTS PER kWh SOLD - RETAIL (Retail -All Classes) 9.80 - . - - - - - - - - - - - - - - - - - - - - - - - - -

9.04¢ 9.06¢ 9.12¢ 9.05¢

.r:. 9.00 3:

~ 8.20 Q) 0..

J!? 7.40 C:

Q) u 6.60 5.80 2013 2014 2015 2016 2017 Average Cents per kWh Sold Average Cents per kWh Sold Less Government Taxes/Transfers 14 L

AVERAGE CENTS PER kWh SOLD - WHOLESALE (Firm Wholesale Customers Only) 6.40 6.09¢ 5.91¢ 5.96¢ 5.93¢ 5.99¢ 6.00

.J:.

3:

~ 5.60 Q)

Q.

.!!l 5.20 I I I u

C:

Q) 4.80 I I I 4.40 2013 2014 I 2015 I 2016 I 2017 Participation Sales and Other Sales There are participation sales agreements in place with other utilities for the sale of power and energy at wholesale from specific generating plants. Such sales are to Lincoln Electric System ("LES"), Municipal Energy Agency of Nebraska ("MEAN") , OPPD, Grand Island Utilities ("Grand Island"), and JEA. The District also sells energy on a nonfirm basis in SPP and through transactions executed with other utilities by The Energy Authority ("TEA").

Transmission Customers The District owns and operates 5,294 miles of transmission and subtransmission lines, encompassing nearty the entire State. The District became a transmission owning member of SPP, a regional transmission organization, in 2009. The District files a rate with SPP annually that provides for the recovery of all transmission revenue requirements associated with transmission facilities equal to or greater than 115 kV. SPP collects and reimburses the District for the use of the District's transmission facilities by entities other than the District's firm requirements customers and all transmission customers still served directly by the District through grandfathered Transmission Agreements.

Fi:nai:ro.cial Ereipornt

Customers and Energy Safes The following table shows customers , energy sales , and peak loads of the System , including participation safes, in each of the three years, 2015 through 2017.

Anytime Peak Megawatt-Hour Safes Load (MW}

Calendar A\erage Number of Wholesale Nati'. Load Percentage Total Percentage Busbar Nati'.

Year Retail Customers Customers<>

1 Sa1es<2l Growth Sa1es <3l Growth 14l Load 2015 91 ,140 82 12,579,390 (2.7) 20,990,883 1.6 2,695.0 2016 91,457 78 12,901 ,989 2.6 18,902,173 (10.0) 2,963.7 2017 91 ,614 78 13,061 ,979 1.2 19,568,548 3.5 2,891 .5 (1 ) At the end of 2017, indudes sales to firm wholesale customers, participation customers (LES, MEAN , JEA, OPPD, Grand Island), and a yearly average of 2 nonfirm customers. In 2016, three of the District's municipal wholesale customers began purchasing power from three of the District's public power district wholesale customers, and one of the District's municipal wholesale customers allowed their contract to terminate.

(2) Native load sales indude wholesale sales to total firm requirements customers and the responsibility of replacement power being procured by the District if the District's generating assets are not operating. Predominantly, native load customers are served under long-term total requirements contracts.

(3) Total sales from the System indude sales to LES from GGS and Sheldon, which sales from Sheldon terminated on December 31 ,2017; to MEAN, JEA, OPPD, and Grand Island from Ainsworth Wnd Energy Facility, which sales commenced October 1, 2005, and terminates on September 30, 2025; to OPPD, MEAN , LES and Grand Island from Elkhorn Ridge Wnd Facility, which sales commenced March 1, 2009, and terminates on February 28, 2029; to MEAN from GGS and CNS, which sale commenced January 1, 2011 , and terminates on December 31 , 2023; to MEAN, LES and Grand Island from Laredo Ridge Wnd Facility, which sales commenced February 1, 2011 , and terminates on January 31 , 2031 ; to OPPD, LES and Grand Island from Broken Bow 1 Wind Facility, which sales commenced December 1, 2012, and terminates on November 30, 2032; to OPPD, LES and MEAN from Crofton Bluffs Wind Facility, which sales commenced November 1, 2012, and terminates on October 31 , 2032; and to OPPD from Broken Bow 11 Wind Facility which sale commenced October 1, 2014, and terminates on September 30, 2039. The District and LES executed an agreement in 2017 to terminate and release LES from the Sheldon Station Participation Power Sales Agreement for years commencing alter December 31 , 2017.

(4) The increase in percentage growth from 2016 to 2017 was due primarily to additional nonfirm energy sales from CNS as a result of 2017 being a non-outage year for the unit. The decrease in percentage growth from 2015 to 2016 was a result of lower nonfirm energy sales due primarily to the planned refueling and maintenance outage at CNS, lower natural gas prices and additional wind generation in the SPP Integrated Market.

Eilil.alilcial Rrep>(!rnt

FINANCIAL INFORMATION The following tables summarize the District's financial position and operating results.

CONDENSED BALANCE SHEETS (in OOO's)

As of December 31 , 2017 2016 2015 Current Assets ....... ...... ....... ........ ................................... . $ 858,872 $ 775,479 $ 764,278 Special Purpose Funds ........ ......... .. .... .. ........................ .. 746,448 782,857 738,967 Utility Plant, Net ..... .... ..................... ....... .... .... ................. . 2,569,898 2,595,767 2,508,971 Other Long-Term Assets ..... ..... ... ..... .... .... ... ..... .. .... .. ....... . 383,701 406,149 353,639 Deferred Outflows of Resources ... .......... .. .................. ..... . 295,402 344,331 40,775 Total Assets and Deferred Outflows .. .. ......................... . $ 4,854,321 $ 4,904,583 $ 4,4061630 Current Liabilities ..................... .. ...... ..... .. ..... ... .. ...... .. .... .. $ 370,501 $ 287,322 $ 218,858 Long-Term Debt ........... .............. ... ... ..... ...... ....... ..... ....... . 1,617,269 1,867,768 1,838,672 Other Long-Term Liabilities ....... ... ... .......... ...... .... ... .... ..... . 1,028,467 1,063,118 727,070 Deferred Inflows of Resources ... ........... .. ........... .. .. .. .. ..... . 351 ,651 271 ,258 289,846 Net Position ......... ............................... .......... ... .... ........ ... 1,486,433 1,41 5,117 1,332,184 Total Liabilities, Deferred Inflows, and Net Position ....... . $ 418541321 $ 4A06 163o CONDENSED RESULTS OF OPERATIONS (in OOO's)

For the years ended Decent>er 31 , 2017 2016 2015 Operating Re1enues ................... .. ........ ..... .......... ... ....... .. $ 1,101 ,642 $ 1,153,997 $ 1,097,216 Operating E>qlenses .............. ....... .. ... ..... .................. ...... . (988,931) (1 ,040,715) {960,259)

Operating Income ..... ...... ........ ...... ... ... .... .. .. .............. .. 112,711 11 3,282 136,957 Investment and Other Income ................ ........ ........... .. .... .. 23,591 31 ,772 22,355 Debt and Other E,q:>enses ..... ....................... ................... . (64,986) (62,121) (68,252)

Increase in Net Position .... ........................ ............ ..... . $ 71 316 $ 821933 $ 91 1060 SOURCES OF OPERATING REVENUES (in OOO's)

For the years ended Oeceni>er 31 , 2017 2016 2015 Rrm Retail and Wholesale Sales ..................................... . $ 875,312 $ 865,661 $ 848,345 Participation Sales ......................................................... . 73,199 77,996 77,192 Olher Sales ................................................................... . 112.,209 89,492 134,612 Olher Operating Re\ienues .............................................. . 76,182 66,060 60,730 l..klearned Re\ienues ******************************************************** {35,260) 54,788 {23,663}

Total Operating Re\ienues .......................................... . $ 1110\642 $ 111 531997 $ 110971216

!Fii nat.li1cial Rep@rt

CONDENSED STATEMENTS OF CASH FLOWS (in OOO's)

For the ~ears ended December 31 , 2017 2016 2015 Net Cash Provided by Operating Activities .. ..... ... .. ....... ...... $ 365,097 $ 253,711 $ 372,503 Net Cash Provided by (Used in) Investing Activities ............ (107,438) 2,374 10,961 Net Cash Used in Capital and Financing Activities ........ ..... (332,584} (238,416} (388,483}

Net Increase (Decrease) in Cash and Cash Equivalents ..... (74,925) 17,669 (5,019)

Cash and Cash Equivalents, Beginning of Year .. .... .... ... .... 102,729 85,060 90,079 Cash and Cash Equivalents, End of Year .... .. .... ... ..... .. . $ 27 804 $ 1021729 $ 851060 Revenues from Firm Retail and \/Vholesale Sales The District allocates costs between retail and wholesale service and establishes its rates to produce revenues sufficient to meet its estimated respective retail and wholesale revenue requirements. \/Vholesale revenue requirements include unbundled costs accounted for separately between generation and transmission. The rates for retail service include an amount to recover the costs of wholesale power service in addition to distribution system costs and government taxes and transfers. The District's wholesale power contracts provide for the establishment of cost-based rates. Such rates can be adjusted at such times as deemed necessary by the District. The wholesale power contracts also provide for the creation of a rate stabilization account. Any surplus or deficiency between revenues and revenue requirements, within certain limits set forth in the wholesale power contracts, may be retained in the rate stabilization account. Any amounts in excess of the limits may be included as an adjustment to revenue requirements in the next rate review. The wholesale power contracts also include a provision for establishing a new/replacement generation fund . This provision would permit the District to collect an additional 0.5 mills per k\/Vh above the normal revenue requirements to be used for future capital expenditures associated with generation.

There was no change to the wholesale or retail rates on January 1, 2018.

The District implemented a 0.6% increase in the District's wholesale rates on January 1, 2017, for all customers.

No increase in retail rates was implemented in 2017.

The District implemented a 0.6% increase in the District's wholesale rates on January 1, 2016, for those wholesale customers who signed the new 2016 20-year wholesale power contract, and a 3.8% increase in the District's wholesale rates on January 1, 2016, for those wholesale customers who remained under the 2002 20-year wholesale power contract. The rate increase was higher for the 2002 Contracts as these customers will pay their share of a catch-up in funding for OPEB costs related to prior service through rates prior to the expiration of their contracts in 2021. The District financed with taxable debt the 2016 Contracts customers' share of the OPEB catdl-up trust funding for 2016 and 201 7 and plans to issue additional taxable debt in 2018 for catch-up trust funding. The customers under the 2016 Contracts will commence payment through rate collections of the related debt service for their share of the catch-up in funding for OPEB costs beginning in 2022, the year after the expiration of the 2002 Contracts, and continue making payments through 2033. No ina-ease in retail rates was implemented *n 2016. Details of the Oisbict's Wholesale Power Contracts are induded in Note 12 in the Notes to Financial Statements.

Revenues from finn sales increased $9.6 million, or 1.1%, from $865.7 million in 2016 to $875.3 million in 201 7.

The increase in revenue was due primarily to a weather-related 1.2% ina-ease in energy sales. Revenues from finn sales increased $17.4 million, or 2.1 %, from $848.3 million in 2015 to $865.7 million in 2016. The increase in revenues from 2015 to 2016 was due primarily to a weather-related 2.6% inaease in energy sales to firm requirements customers.

Revenues from Participation Sales The District has participation sales agreements with other uti ities that share operating expenses on a pro rata basis. Revenues from participation sales deaeased rrom $78.0 m ion in 2016 to $73.2 million *n 2017, a 18

reduction of $4.8 million. The reduction was due primarily to lower demand revenues for GGS and CNS, along with lower wind participation energy sales. Revenues from participation sales increased from $77.2 million in 2015 to $78.0 million in 2016, an increase of $0.8 million. The District and LES executed an agreement in 2017 to terminate and release LES from the Sheldon Station Participation Power Sales Agreement for years commencing after December 31 , 2017.

Revenues from Other Sales Other sales consist of sales in SPP's Integrated Market and nonfirm sales to other utilities. TEA, of which the District is a member, has energy marketing responsibilities for the District's other and nonfirm off-system sales and the related management of credit risks. Other sales increased from $89.5 million in 2016 to $112.2 million in 2017, an increase of $22.7 million. The increase was a result of higher energy sales due to no refueling and maintenance outage at CNS and higher prices in the SPP Integrated Market due to higher natural gas prices.

Other sales decreased from $134.6 million in 2015 to $89.5 million in 2016, a decrease of $45.1 million. The decrease was a result of reduced nonfirm revenues due to lower energy sales due to the planned refueling and maintenance outage at CNS, lower natural gas prices, and additional wind generation in the SPP Integrated Market.

Other Operating Revenues Other operating revenues consist primarily of revenues for transmission and other miscellaneous revenues.

These revenues were $76.2 million, $66.1 million, and $60.7 million in 2017, 2016, and 2015, respectively. The majority of these revenues were from other SPP transmission customers for their share of qualifying transmission upgrade projects of the District.

Unearned Revenues Under the provisions of the District's wholesale power contracts, any surplus or deficiency between net revenues and revenue requirements, within certain limits set forth in the wholesale power contracts, may be adjusted in the rate stabilization account. Any amounts in excess of the rate stabilization limits may be induded as an adjustment to revenue requirements in the next rate review. A similar process is followed in accounting for any surplus or deficiency in revenues necessary to meet revenue requirements for retail electric service. Under generally accepted accounting principles for regulated electric utilities, the balance of such surpluses or deficiencies are accounted for as -regulatory liabilities or assets", respectively.

The District recognizes net revenues in excess of revenue requirements in any year as a deferral or reduction of revenues. Such surplus revenues are exduded from the net revenues available under the General Revenue Bond Resolution ("General Resolution*) to meet debt service requirements for such year. Surplus revenues are induded in the detennination of net revenues available under the General Resolution to meet debt service requirements in the year that such surplus revenues are taken into account in setting rates. The District recognizes any deficiency in revenues needed to meet revenue requirements in any year as an accrual or increase in revenues, even though the revenue accrual will not be realized as -cash" until some future rate period.

Such revenue deficiency is *nduded, in the year accrued, in the net revenues available under the General Resolution to meet debt service requirements for such year. Revenue deficiencies are exduded in the determination of net revenues available under the General Resolution to meet debt service requirements in the year that such revenue deficit is taken into account in setting rates.

The District deferred or decreased revenues a net amount of $35.2 million in 2017. The District's revenues in 2017 from electric sales to retail, wholesale, and other utilities resulted in a surplus, or over collection of costs, of

$44.9 million, which was deferred (decrease in revenues). In addition, the wholesale rates that were in place for 2017 induded a refund of $6.7 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred. Accordingly, the 2017 revenues from electric sales, which reflect the surplus being refunded, were offset by a revenue adjustment (increase in revenues) for such amount The District also deferred or deaeased revenues by $20.0 mil ion for the pre-collection of CNS refueling and maintenance outage costs. This regulatory liabi ity will be elim*nated through revenue recog ition during the 2018 outage year. In addition, the D*stnct recognized or

creased revenues by Financial Rep0rt

$23.0 million for OPEB expenses related to past service for wholesale customers under the 2016 Contracts. The OPEB expenses were included in 2017 rates and financed with proceeds from General Revenue Bonds, 2016 Series E (Taxable) .

The District recognized or increased revenues a net amount of $54 .8 million in 2016. The District's revenues in 2016 from electric sales to retail , wholesale , and other utilities resulted in a surplus, or over collection of costs , of

$10.0 million, which was deferred (decrease in revenues) . In addition , the wholesale rates that were in place for 2016 included a refund of $17.4 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred. Accordingly, the 2016 revenues from electric sales, which reflect the surplus being refunded , are offset by a revenue adjustment (increase in revenues) for such amount. The District also recognized or increased revenues by $24 .7 million for CNS fall refueling and maintenance outage costs , which costs were pre-collected for in 2015. This regulatory liability was amortized through revenue during the 2016 outage year. In addition , the District recognized or increased revenues by $22 .7 million for OPEB expenses related to past service for wholesale customers under the 2016 Contracts. The OPEB expenses were included in 2016 rates and financed with proceeds from General Revenue Bonds, 2016 Series E (Taxable) .

The District deferred or decreased revenues a net amount of $23.7 million in 2015. The District's revenues in 2015 from electric sales to retail, wholesale, and other utilities resulted in a surplus, or over collection of costs, of

$11 .0 million, which was deferred (decrease in revenues). In addition, the wholesale rates that were in place for 2015 included a refund of $12 .0 million of surplus net revenues from past rate periods. Such surplus had previously been accounted for as a reduction in revenues in the year(s) the surplus occurred. Accordingly, the 2015 revenues from electric sales , which reflect the surplus being refunded , were offset by a revenue adjustment (increase in revenues) for such amount. The District also deferred or decreased revenues by $24. 7 million for the pre-collection of CNS refueling and maintenance outage costs. This regulatory liability was eliminated through revenue recognition during the 2016 outage year.

The balance of the regulatory liability for unearned revenues to be applied as credits against revenue requirements in future rate periods was $206.9 million, $168.7 million, and $176.1 million, as of December 31, 2017, 2016, and 2015, respectively.

Operating Expenses The following chart illustrates operating expenses for the years ended December 31, 201 5 through 2017.

$1,200 Power Purchased & Fuel

$1,041

$1,000 Production Operation & Maintenance ("O&M")

in Transmission & Distribution O&M C: $800

.5!

-i...

U)

$600 Customer Service & Information Administrative & General 0 $400 Cl Decommissioning

$200 Depreciation & Amortization

$0 Other 2015 2016 2017 20

Total operating expenses in 2017 were $988.9 million, a decrease of $51 .8 million from 2016. Total operating expenses in 2016 were $1 ,040.7 million, an increase of $80.4 million from 2015. The changes were due primarily to the following :

Power purchased and fuel expenses were $342.8 million, $347.6 million, and $365.1 million in 20 17, 2016, and 2015, respectively. These expenses decreased $4 .8 million in 2017 as compared to 2016 due primarily to fewer energy purchases in the SPP Integrated Market as there was no refueling and maintenance outage at CNS. The favorable power purchased variance was partially offset by an unfavorable fuel variance from higher generation in 2017. These expenses decreased $17.5 million in 2016 as compared to 2015 due primarily to additional energy purchases from NC2 and the wind facilities, and lower fuel costs as the result of decreased generation.

Production operation and maintenance expenses were $243.3 million, $287.7 million, and $242.8 million in 2017, 2016, and 2015, respectively. These costs decreased $44.4 million in 2017 as compared to 2016 due primarily to the costs associated with a planned refueling and maintenance outage at CNS completed on November 8, 2016.

No such outage occurred in 2017. In 2016 these costs increased $44.9 million due primarily to the costs associated with the planned refueling and maintenance outage at CNS.

Transmission and distribution operation and maintenance expenses were $100.9 million, $102.0 million, and

$87.3 million, in 2017, 2016, and 2015, respectively. These costs decreased $1 .1 million in 2017 as compared to 2016. These costs increased $14.7 million in 2016 as compared to 2015 due primarily to higher fees charged by SPP for the District's share of qualifying transmission upgrade projects, including an SPP resettlement for prior periods for the implementation of a tariff provision to compensate transmission upgrade sponsors for qualifying upgrades used by other transmission customers.

Customer service and information expenses were $16.0 million, $17.7 million, and $1 7.2 million, in 20 17, 2016, and 2015, respectively.

Administrative and general expenses were $106.2 million, $94.1 million, and $66.3 million, in 2017, 2016, and 2015, respectively. Administrative and general expenses increased $12.1 million in 2017 as compared to 2016 due primarily to a reclassification in 2017 to include all OPEB costs with administrative and general expense, a portion of these costs were included in operation and maintenance expense in prior years. These costs increased

$27.8 million in 201 6 as compared to 2015 due primarily to OPEB expenses related to past service and included in 2016 rates. Details regarding OPEB, including the early adoption of new accounting guidance in 201 6, are ind uded in Note 11 in the Notes to Financial Statements.

Decommissioning expenses were $19.9 million, $21.4 million, and $14.7 million, in 2017, 2016, and 2015, respectively. Prior to 2017, decommissioning expenses only represented the net amount accrued each year for the future decommissioning of CNS. Commencing in 2017, decommissioning expenses also ind uded amounts collected in rates for the future decommissioning of certain non-nuclear utility plant assets. Decommissioning expenses are recorded in an amount equivalent to the income on invesbnents in the nuclear facility decommissioning fund plus amounts collected for decommissioning in the rates for electric service in such year.

Decommissioning expenses decreased $1 .5 million in 2017 as compared to 2016. This decrease was due to a

$7.4 million decrease in invesbnent income for the nudear facility decommissioning fund, which was partially offset by $5.9 million in collections for decommissioning of certain non-nuclear utility plant assets.

Decommissioning expenses increased by $6.7 million in 2016 as compared to 2015 due to an inaease in interest income on invesbnents. No additional amounts for decommissioning were collected through rates in 2016 and 2015.

Depreciation and amortization expenses were $1 22.6 million, $1 33.7 million, and $130.2 mi lion, in 2017, 2016, and 201 5, respectively. The decrease in depreciation and amortization expenses was due primarily to a change *n the estimate to longer asset lives for certain transmission assets.

Increase in Net Posiliion The increase in net position was $71 .3 mllion, $82.9 million, and $91 .1 million,

2017, 2016, and 2015, respectively. The change *n net position

2017 as compared to 2016 decreased $11.6milion and was due Fimamcial eipIDri

primarily to a decrease in 2017 revenue requirements from reduced collections for principal payments for debt service and utility plant additions, an increase in unrealized investment losses and lower capitalization of interest during construction. These decreases in net position were partially offset by a reduction in depreciation expense.

The change in net position in 2016 as compared to 2015 decreased $8.2 million and was due primarily to a decrease in 2016 revenue requirements from decreased collections for principal payments for revenue bonds and construction from revenue, partially offset by increased collections for principal payments on commercial paper notes The following chart illustrates the District's operating revenues, other revenues, operating expenses, and other expenses for the years ended December 31 , 2015 through 2017.

Revenues & Expenses

$1,250 . . . . - - - - - - - - - - - - - - - - - - - - - - - -

$1,200 +-----------------------

U) $1,150 c:

L - - - - - - -lii~- - - - - - - - - -

.!:! $1,100 +----Ul--- - - - ----1 Other Expenses

[ $1,050 Operating Expenses I!! $1,000 + - -----t Other Revenues

~ $950 _ __,

Operating Revenues o $900 - i - - --1

$850 + - - --1

$800 -'--~-'-- - -

2015 2016 2017 FINANCIAL MANAGEMENT POLICY The District has a Financial Management Policy (the "Policy~). which is subject to periodic review and revisions by the Board. This Policy represents general financial strategies and procedures that are implemented to demonstrate financial integrity and fiscal responsibility in the management of the District's business and its assets. Employees must abide by all applicable District bylaws, Board resolutions, bond resolutions, federal and state laws, other relevant legal requirements and the Policy.

DEBT SERVICE COVERAGE Under the Policy, U,e District has established a minimum debt service coverage ratio on the General Revenue Bonds of 1.5 times the debt service on the General Revenue Bonds. The District's debt service coverage ratio was 2.13, 1.98, and 1.84, in 2017, 2016, and 2015, respectively. The coverage was provided primarily by U,e amounts collected in operating revenues for utility plant additions, for principal and interest payments on outstanding commercial paper notes and revolving credit agreements, and for payments to Uiose municipalities served by the District under long-term PRO Agreements. The increase in the 2017 debt service coverage ratio over 2016 and the increase in the 2016 debt service coverage ratio over 2015 were primarily due to a decrease in the required debt service deposits.

ANANC NG ACTIVITIES Good credit ratings allow the 0-strict to borrow funds at more favorable interest rates. Such ratings reflect only the view of such rating organizations, and an explanation of the significance of such rating may be obtained only from the respective rating agency. There is no assurance that such ratings will be maintained for any given period of time or that they will not be revised downward or be withdrawn entirely by the respective rating agency if, in its 22

judgment, circumstances so warrant. Any such downward revision or withdrawal of such ratings may have an adverse effect on the market prices of bonds.

The District's credit ratings on its revenue bonds were as follows:

Moody's Investors Service .. .. .. .... ..... ...... .... .. ..... .. ... ..... ....... ...... ... ........ ... ... ... . A 1 (stable outlook)

Standard & Poor's Ratings Services .. .. .......... ... .... .... ... ...... ....... .......... .... ..... . A+ (stable outlook)

Fitch Ratings .... ........... ... ............ .............................. ...... ................ ... ............ A+ (stable outlook)

The District plans, pursuant to the Policy, to issue separate series of indebtedness, including separate series of General Revenue Bonds, for production projects and for transmission projects. No more than 20.0% of the amount of outstanding indebtedness issued for production projects, calculated at the time of issuance of each series of such indebtedness, or $200.0 million, whichever is less, will be permitted to mature after January 1, 2036, the end of the 2016 Contracts. Transmission indebtedness issued for transmission projects is expected to mature over the useful life of the asset that is being financed. New transmission indebtedness may mature after January 1, 2036. The District's transmission indebtedness is payable from the revenues received during the term of the 2016 Contracts and from retail sales and transmission revenues received under various SPP tariffs. After January 1, 2036, transmission indebtedness will be payable from revenues to be derived from wholesale and retail customers who use the District's transmission facilities, as well as revenues from various SPP tariffs.

On January 1, 2018, the District called the remaining outstanding General Revenue Bonds, 2012 Series C, with a principal amount that aggregated $4.2 million as of December 31 , 2017. The District plans to issue additional revenue bonds in 2018 to refund existing debt and to fund a portion of OPEB costs for customers under the 2016 Contracts.

In June 2017, the District executed a Tax-Exempt Revolving Credit Agreement ("TERCA") with two commercial banks to provide for loan commitments to the District up to an aggregate amount not to exceed $150.0 million, which replaced its Commercial Paper Notes program.

In April 2017, the District issued General Revenue Bonds, 2017 Series A and 2017 Series B, in the amount of

$86.0 million to refund the General Revenue Bonds, 2007 Series 8 . The refunding reduced total debt service payments over the life of the bonds by $11 .8 million, which resulted in present value savings of $10.0 million.

In November 2016, the District issued General Revenue Bonds, 2016 Series C and 2016 Series 0 , in the amount of $113.5 million to finance the costs of certain generation and transmission capital projects and refund $61 .7 million Tax-Exempt Commercial Paper r TECP"). The District also issued in November 2016, General Revenue Bonds, 2016 Series E (faxable), in the amount of $56.1 million to fund a portion of OPEB costs for customers under 2016 Contracts.

In February 2016, the District issued General Revenue Bonds, 2016 Series A and 2016 Series 8 , in the amount of

$139.2 million to advance refund $138.9 million of bonds and refund $16.5 million of TECP. The refunding reduced total debt service payments over the life of the bonds by $29.8 million, which resulted in present value savings of $20.8 million.

In January 2016, the District issued TECP in the amount of $43.6 million to refund a portion of the General Revenue Bonds, 2005 Series C and General Revenue Bonds, 2006 Series A In February 2016, $16.5 million of TECP was refunded by General Revenue Bonds, 2016 Series A and Series B.

Details of the District's debt balances and activity are induded in Note 7 in the Notes to Financial Statements.

CAPITAL REQUIREMENTS The B<>arlkluthorized capital projects totaled approximately $85.0 mi lion, $109.5 m*mon, and $501 .0 million, in 2017, 2016, and 2015, respectively. The District's capital requirements are funded with monies generated from operations, debt proceeds, and other available reserve funds.

FiNar,mial R~FJ0rt

Capital projects for 2017 included:

$14.7 million for implementation of Advanced/Smart Metering and Interfaces

$11 .2 million for construction of an evaporation pond at GGS

$6.4 million for refurbishment of a 115 kV substation in Beatrice, Nebraska Capital projects for 20 16 included:

$22.0 million for construction of a high-voltage transmission line from the Muddy Creek substation to Ord, Nebraska

$16.4 million for construction of a high-voltage substation in Holt County, Nebraska and expansion of the GGS 345 kV substation

$12.6 million for installation of stainless steel liners in coal silos at GGS Units 1 and 2 Capital projects for 2015 included:

$346.8 million for construction of a high-voltage transmission line and related substations from a GGS substation north to Cherry County, Nebraska and east to a new substation in Holt County, Nebraska

$33.9 million for modifications to the hot flue gas ductwork at GGS Unit 2

$33.1 million for construction of a high-voltage transmission line from a substation in Stegall, Nebraska to a substation in Scottsbluff, Nebraska There were other authorized capital projects for renewals and replacements to existing facilities and other additions and improvements of $52.7 million, $59.0 million, and $87.2 million for 2017, 2016, and 2015, respectively.

The Board-authorized budget for capital projects for 2018 is $118.9 million. Specific capital projects for 2018 indude:

$25.5 million for retrofit of the low pressure turbine for GGS Unit 2

$4.5 million for refurbishment of the main generator exciter at CNS

$4.3 million for a training facility in Yonc, Nebraska The following chart illustrates the Board-authorized capital projects for the years ended December 31, 2015 through 2017, including the Board-authorized budget for the year ended December 31, 2018.

$600

$500

.~-~- - $501 I ll C:

.2 $400

ii: $300 I ll Ill

$200 0 $1 19 C $110

$100 2015 201 6 2017 201 8 Budget RESOURCE PLANNING The District uses a diverse mix of generation resources sudl as coal, nuclear, natural gas, hydro and wind to meet its firm requiremen customer's needs. In 2017, the non<arbon energy resources as a percentage of native load sales were 65%.

Finan:cial l&~J!)@lit 24

The District's last comprehensive 20-year Integrated Resource Plan ("IRP") was completed and approved by the Board in 2013 . Since that time there have been several changes in assumptions that have now been included in the limited scope, five-year IRP approved by the Board at their March 2018 meeting. The 2018 IRP shows the District does not require new resources for the next five years. The changes in assumptions in the 2018 IRP included :

2016 Wholesale Power Contracts - The negotiation of new contracts with the District's wholesale customers, which extended the term 20 years for all but ten of the current customers. The new contract allows a 10% renewable self-supply option, or 2 MW, whichever is greater.

Cooper Nuclear Station Power Uprate - The decision by the Board not to proceed with a power uprate at its nuclear facility, a low-cost resource option included in the 2013 IRP, due to a more detailed evaluation of costs and market risk.

Renewable Energy - The addition of two new wind facilities of which 74 MW will be used to serve the District's firm customers. This brings the total amount of wind in the portfolio of resources serving its firm customers to 281 MW.

Sheldon Station - The recapture of approximately 65 MW of capacity and energy from Sheldon after the Board approved ending the participation sale for 30% of Sheldon's output to LES.

Southwest Power Pool Integrated Market - In 2014, SPP commenced a Day-Ahead, Ancillary Services, and Real-Time Balancing Market. The District, in tum , began participating as a member utility in the energy market place. The market coordinates next-day generation across its footprint to maximize cost effectiveness for its members. The District sells and purchases power in the SPP Integrated Market. A significant amount of renewables, primarily wind, continue to be added in the SPP Integrated Market.

Hydrogen Generation - Monolith Materials, Inc. ("Monolith") has expressed an interest to construct and operate a carbon black facility adjacent to the District's Sheldon coal-fired generating facility in Nebraska.

The construction of the carbon black facility is expected to be accomplished in two phases. The electric load to serve any Monolith facility will be served by Norris Public Power District, a firm wholesale customer of the District. At full buildout, Monolith may be the single-largest industrial customer served in the District's territory. The District entered into a 20-year contract with Monolith to purchase the carbon black plants' production of hydrogen rich tail gas, which will be produced by Monolith during production of carbon black. The District will have to convert its existing coal-fired boiler at Sheldon Unit No. 2 to bum the hydrogen rich tail gas. The boiler conversion is expected to result in a reduction of carbon dioxide

("CO2"), sulfur dioxide ("S02"), mercury, and other air emissions. Groundbreaking for Phase 1 occurred in October 2016 and is expected to be mechanically complete in 201 8 and fully operational in 2019.

Phase 2 construction is planned to begin in the second half of 2020. The commercial operation date (defined jointly as the date on which Phase 2 is capable of sufficient, steady state hydrogen rich tail gas supply, and the Sheldon Unit No. 2 boiler has been converted and commissioned) is scheduled for the second quarter of 2021.

ENERGY RISK MANAGEMENT PRACTICES The nature of the District's business exposes it to a variety of risks, induding exposure to volatility in electric energy and fuel prices, uncertainty in load and resource availability, the aeditworthiness of its counterparties, and the operationa risks associated with transacting in the wholesale energy markets.

To help manage energy risks, induding the risks related to the District's participation in the SPP Integrated Market, the District relies upon TEA to both transact on its behalf in the wholesale energy markets and to develop and recommend strategies to manage the District's exposure to risks in the wholesale energy markets.

TEA combines a strong knowledge of the District's system, an in-depth understanding of the wholesale energy markets, experienced people, and state-of-the-art technology to deliver a broad range of standardized and customized energy products and services to the District TEA has assisted the District in developing its Energy Risk Management ("ERM~) program. The program originates with the Board-approved ERM Governing Policy and the ERM-Approved Products and Limits Standard.

These doouments establish the philosophy, objectives, delegation of aulhorilies, approved products and their imits on the 0-stricfs energy and fuel activities necessary to govern its ERM program. The objective of the ERM program is to *ncrease fuel and energy price stability by hedging the risk of sig ifiicant adverse impacts to cash Winancial Rep0rt

flow. These adverse impacts could be caused by events such as natural gas or power price volatility, or extended unplanned outages. The ERM program has been developed to provide assurance to the Board that the risks inherent in the wholesale energy market are being quantified and appropriately managed.

ECONOMIC FACTORS Preliminary data indicated Nebraska's economy experienced a decline in 2017, after three years of slowing growth rates. The State's inflation adjusted, estimated gross state product ("GSP") decreased by 0.8% from the third quarter of 2016 to the third quarter of 2017. The U.S. economy experienced a 2.2% increase in national gross domestic product over the same 12-month period. Previous estimates of Nebraska's GSP were also revised downward. The third quarter estimates for 2016, 2015, and 2014 were decreased 1.3%, 0.9%, and 0.7% ,

respectively. Nebraska's decline in GSP over the latest 12 months was due to declines in the "Agriculture ,

forestry, fishing , and hunting", "Real estate and rental and leasing", "Management of companies and enterprises",

"Construction" and "Utilities" industries.

Nebraska and the Midwest region continue to experience unemployment rates that are below the national average. Nebraska's average annual unemployment rate decreased from the revised 2016 value of 3.1% to 2.9%

in 2017. These rates were well below the national December seasonally adjusted unemployment rates of 4.4%

and 4.7% in 2017 and 2016, respectively. After several years of consistently being one of the three states with the lowest unemployment rates, Nebraska's preliminary December 2017 and revised December 2016 unemployment rates were the fourth and ninth lowest in the nation, respectively. The District continues to monitor changes in national and global economic conditions , as these could impact the cost of debt and access to capital markets.

CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY The Electric Utility Industry In General The electric utility industry has been, and in the future may be, affected by a number of factors which could impact the financial condition and competitiveness of electric utilities, such as the District. Such factors include, among others:

effects of compliance with changing environmental, safety, licensing, regulatory, and legislative requirements,

changes resulting from energy efficiency and demand-side management programs on the timing and use of electric energy,

increasing demand by customers for self-managing energy use to lower their energy costs,

other federal and state legislative and regulatory changes,

increased wholesale competition from independent power producers, marketers, and brokers,

low market prices for wholesale power,

~self-generation* by certain industrial and commercial customers,

issues relating to the ability to issue tax-exempt obligations,

severe restrictions on the ability to sell to nongovernmental entities electricity from generation projects financed with outstanding tax-exempt obligations,

changes from projected future load requirements

increases in costs,

shifts in the availability and relative costs of different fuels,

inadequate risk management procedures and practices with respect to, among other things, the purchase and sale of energy, fuel, and transmission capacity,

effects of financial instability of various participants in the power market,

dimate change and the potential contributions made to dimate change by coal-fired and other fossil-fueled generating units,

increased regulation of nuclear power plants *n the United States resulting from the earthquake and tsunami damage to certain nuclear power plants in Japan, and

issues relating to cyber and physical security.

Any of these general factors (as well as other factors) could have an effect on the financial condition of the District.

iEi,llalQoial Report 26

Competitive Environment in Nebraska While wholesale competition is expected to increase in the future , there is a Nebraska statute that prohibits competition for retail customers. Pursuant to state statutes, retail suppliers of electricity have exclusive rights to serve customers at retail in their respective service territories. Any transfer of retail customers or service territories between retail electric suppliers may be done only upon agreement of the respective retail electric suppliers and/or pursuant to an order of the Nebraska Power Review Board. While state statutes do not provide for wholesale suppliers of electricity to have exclusive rights to serve a particular area or customer at wholesale, wholesale power suppliers are permitted to voluntarily enter into agreements with other wholesale power suppliers limiting the areas or customers to whom they may sell energy at wholesale. The District has entered into several such agreements.

Fi:nam1cial R!e_l!><!ll1t

REPORT OF INDEPENDENT AUDITORS To the Board of Directors of the Nebraska Public Power District:

We have audited the accompanying financial statements of Nebraska Public Power District (the "District"), which comprise the balance sheets as of December 31 , 2017 and 2016, and the related statements of revenues, expenses, and changes in net position , of cash flows , and the related notes to the financial statements for the years then ended .

Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design , implementation , and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the District's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the District's internal control. Accordingly, we express no such opinion . An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion In our opinion , the financial statements referred to above present fairty, in all material respects, the financial position of the District as of December 31 , 2017 and 2016, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter As discussed in Note 1 and Note 9 to the financial statements, the District changed the manner in which it accounts for Asset Retirement Obligations in 2017 . Our opinion is not modified with respect to this matter.

Other Matters The accompanying management's discussion and analysis and the supplemental schedules on pages 11 through 27 and 65 through 6 7, respectively, are required by accounting principles generally accepted in the United States of America to supplement the basic financial statements_ Such infonnation, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary

nfonnalion in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the *nfonnation and comparing the infonnalion for consistency with management's responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audits of the basic financial statements. We do not express an oJfn*on or prov'tde any assurance on the -nfonnalion because the imited procedures do not provide us with sufficient evidence to express an op"nion or provide any assurance.

Our audits were conducted for the purpose of l'onning opin ons on the financial statements that co lectively compl1ise the Disb1idt's basic fina cial statements. The sralistical review is presented for purposes of additional analysis and -s not a required part of lhe basic financial statements. Such informaliion has ot been subjected to the a diting procedures applied in the audits of the basic fina cial statements, and aooordingly, ~ do not express an op*nion or provide any ass ranee on it

~0)

Sit. Lou*s, Misso ri April 12, 2018 Fin.alilcial B!eport 28

FINANCIAL STATEMENTS Nebraska Public Power District Balance Sheets as of December 31 , (in OOO's) 2017 2016 ASSETS AND DEFERRED OUTFL0\11/S Current Assets :

Cash and cash equivalents ......... .... ..... ... ...... ............. ... .. ... ...... ........ ........ . . $ 27,804 $ 102,729 I nvestrnents ... ....... ...... ............... ........... .. ... .... ........ ... ......... ....... ..... ....... ... . 539,173 373,331 Receivables, less allowance for doubtful accounts of $541 and $530, respectively ....... ...... ..... ...... .... ... .... .. ..... ... ........ .. ....... . 120,254 123,905 Fossil fuels, at average cost ...... ........ .. ... ..... .......... ... .... .......... .......... .. ...... . 43,264 43,620 Materials and supplies, at average cost .......... ..... ... ...... ....... .......... .... ..... ... . 111 ,644 11 4,640 Prepayments and other current assets .. ........ ..... ......... .... ............. .. ....... ... .. 16 733 17 254 858,872 775 479 Special Purpose Funds:

Construction funds ..... .. ............ ........... .... .. ....... .... ... ........ ..... ........... ........ . 54,808 106,204 Debt reserve funds ....... ...... ............. ........ ........ ............ .... .... ........ ... ......... . 88,764 90,032 El'Tl)loyee benefit funds ....... ............ ............................ ..... .. ........... ....... ... . 1,934 4 ,851 Decorm,issioning funds .. ... .. ... ........... ......... ...... .... .... ........................... .... . 600,942 581 770 746 448 782 857 Utitity Plant, at Cost Utitity plant in service ......... ..... .. ... .. .. .................. ........ ......... ........... .......... . 4,928,370 4 ,835,829 Less reserve for depreciation ........... .... ....... ...... .... ...... .......... .... ....... ... ... .. . 2,658 206 2 573 645 2,270,164 2,262,184 Construction IMlrk in progress ... .... ........... ... .. ........... .... ... ......................... . 133,515 135,853 Nuclear fuel, at amortized cost ...... ... .... ... ........ ......... ... ..... ...... .. ... ....... .. .... . 166 219 197 730 2,569,898 2,595,767 Other Long-Term Assets:

Regulatory asset for other postel'Tl)loyment benefits ....... ..... ........... ... .... ..... . 210,362 221 ,973 Long-term capacity contracts .............. .... .......... .... .. .... ......... ...... ... ........ .. . . 152,831 159,445 Unamortized financing costs .............. ... .. ...... ... ..... ....... ............. ...... ..... .. ... 8,201 8,945 Investment in The Energy Authority .... ... ......... ......................... ..... .... ..... .... . 6,175 6,370 Other ... .. ......... .... ..... .. .. ..... .......... ............................. ........... .......... ... ...... . . 6132 9416 383 701 406149 Total Assets ..... ... .... .... ........ ...... ............... ...... ... .... ... .. ......... ... ........ . 4558 919 4,560,252 Deferred Oulflows of Resources:

Asset retirement obligation ....... .. ........... ..... .. .. ........ .... .. .... ....... ... ........ .. .... . 222,369 219,378 Unamortized cost of refunded debt *********** ****** *********** ** ** *****-*- *-*- *-** **** ******** 38,430 42,664 Other poslernployment benefits .... .. ................ ...... .. .... ..... ...... .. .. .... ....... .... . . 34,603 82,289 295,402 344 331 TOTAL ASSETS AN) DEFERRED OUTFLCMIS **** ** ** ** ******** ****- ***** ***** *** ********** I 4,854,321 I 4,904,583 LIABILITIES, DEFERRED IIIFLCMIS, AN) !ET POSITION Current Liabilities:

Rellenue bonds, current **** ************ ********* ***********************-*******-**-*****-*** ******* $ 98,205 $ 8 1,250 Noles and c redit agreements, current ............................................ **--******-* 165,212 74,000 Accounts payable and accrued liabilities *-**--*-******-*--------- -*-------- -****-*-*--*--**- 64,981 87,061 Accrued in lieu of tax payments ... *- ...... ..... ...... ........ *****-************ ................ . 10,000 10,008 Accrued payments ID retail c011TI1Unities **********-**************************************** - 6,074 6,037 Accrued ~ t e d absences *--***-*-*-*-*-*-*-**-************-******-*-**--*****-****----- 16,971 17,594 Olher *-*- --*- *-***- *****-***-*-***********-*-*******************************************-******************* 9058 11372 370501 287,322 Long-Term Debt Rellenue bonds, net of current**-*-******-**-**-*--*-*-*****-*****-************************-***** 1,548,269 1,678,844 Noles and credit agreements. net d current **************-******************************** 69000 188924 1,617,269 1867768 Olher Long-Term Liabilities:

Asset retirement obligation . *********************************************-*-*********************-* 823,794 801 ,147 Nell: dher ~ y m e n l benefit liability ................................................... 182,835 258,609 Olher **********-**-***********-*-*-*****-********************** ********-************************************ 21 838 3362 1,028,467 1,063,118 Total Liabilities ***********************-******************************************************** 3,016,237 3,218,208 Defened lnfbws d Resourt:es::

lklearned relBIIJeS ***** * ****** **** *** * * **** ******** ** ** **************** * * * **** ********* ** * * ******* ** 206,927 168,,710 Olher deferred infbws ............................................................................. . 144.724 102,548 351,651 271,258 Nell: Pos* "oo:

Nell: *mes!lnent in capilal asse1s ................................................................ . 1,029,230 928,967 Resilricied ********-*****-*********-***-******************************************************************* 37,782. 38,776 lJlnlresilrit:I ............... ****************************************************************************** 4 19421 447.374 1.,486.433 1,.415,117 lOTAL LIABILITIES, DEFERRED IIIFLONS, AN) tET POSITIOII .................. i 4 .,854,321 i 4,904.,583 The accompanying notes to financial statements are an integral part of these statements.

Fii:nwncial R!epornt

Nebraska Public Power District Statements of Revenues, Expenses, and Changes in Net Position For the years ended December 31 , (in OOO's) 2017 2016 Operating Revenues .... .......... .. ..... ...... ..... ....... ....................... ... .... .. ..... ..... .... . $ 1,101 ,642 $ 1,153,997 Operating Expenses:

Power purchased ........ ........ ........... ....... ...... ..... ........ .... ... ............ ... ..... .... . 161 ,963 177,121 Production:

Fuel ... .. ... ........ ..... .... ... ... .... ... ....... .... ... .... ...... .... ........ ............. ... .. ...... . . 180,858 170,450 Operation and maintenance ..... ...... .............. ... .......... ..... ..... ....... ..... .... . . 243,332 287,672 Transmission and distribution operation and maintenance ................. ....... ... . 100,945 101 ,952 Customer service and information ...... ..... ..... .............. ............ ......... .... .. .. .. . 15,988 17,696 Administrative and general ......... ... ....... ............... ......... ... ... ... ..... ..... ..... .... . 106,190 94 ,112 Payments to retail communities ..... ......... ... ........ .. ...... ... ...... ..... ......... ... ..... . 27,102 26,553 DecomlTlissioning .... ..... ... ...... .............. ...... ..... .. ....... .. ....... ............... ..... ... . 19,934 21 ,429 Depreciation and amortization .. ........ ..... .. .... ....... ..... ........... .............. .. ...... . 122,559 133,666 Payments in lieu of ta>les .......... ......... .. ..... .. .. ........ .. .... ..... .. ..... ......... .. ... ... . 10,060 10,064 988,931 1,040,715 Operating Income .. .......... ......... ... .. .......... ... ... ........... ... ........ ....... ...... .. .... ..... . 112,711 113,282 Investment and Other Income:

Investment income .. .. .......... ... ... .. ..... .... .. ..... ... .. ... ........ ..... ............ ..... ...... . . 20,091 28,239 Other income ..... .. .... ........ ......... ........ .... ..... .... ....... ... .... ..... ... .. ... ...... .. .. .... . 3,500 3,533 23,591 31 ,772 Increase in Net Position Before Debt and Other Expenses .. .... .. .... ... ........ ... ..... . 136,302 145,054 Debt and Other E>cpenses:

Interest on long-term debt ..... ... ...... .... ............. ..... ..... .. .... ... ....... .... ........... . 76,186 75,415 Alowance for funds used during construction ......... ............. .. ........ ..... .. ..... . (2,3 17) (4,120)

Bond premium amortization net of debt issuance expense ........ ................. .. (12,598) (11 ,427)

Other expenses ........... .. ............. ............. ...... ............... ...... ........... .. ..... .... . 3,715 2,253 64,986 62,121 Increase in Net Position ............ ................ .......... ..... ..... .... .......................... .. . 71,316 82,933 Net Position:

Beginning balance .................................................................................... . 1,41 5,117 1,332,184 Ending balance ........................................... ............................................. . $ 1,486,433 $ 1,415,117 The accompanying notes to financial statements are an integral part of these statements.

f i~mmia[ Rr~J)(iHit 30

Nebraska Public Power District Statements of Cash FloVvS For the years ended December 31 , (in OOO's) 2017 2016 Cash FloVvS from Operating Activities:

Receipts from customers and others ...... .. ........ ... .. ......... ... ............... .. .... ... . $ 1,112,281 $ 1,067,143 Other receipts ........... ... ... ..... .................. ........ .... .............. ......... ..... ... ...... . 679 209 Payments to suppliers and vendors ....... ........ ... ..... .... .... ....... .................... . . (503,685) (565,252)

Payments to employees .......... ...... ............. .. .. ....................... ......... ......... .. (244,178) (248,389)

Net cash provided by operating activities ............... ..... ................. .. .... ... . 365,097 253,711 Cash FloVvS from Investing Activities:

Proceeds from sales and maturities of investments ....... ... ... ........................ . 2,792 ,011 2,775,601 Purchases of investments .. .... ........ .................. ........ ........... ..................... . (2,920,411) (2,800,722)

Income received on investments ...... ........... .. ..................... ............ ... ........ . 20,962 27,495 Net cash prm,;ded by (used in) investing activities ............ .. ...... .. ..... ... .. . . (107,438) 2,374 Cash Flows from Capital and Related Financing Activities:

Proceeds from issuance of bonds .... ................... ... ..... .. ... .................... .... . 96,957 354,776 Proceeds from notes and credit agreements ......... ... .. ...... ........ .... ....... ...... .. 98,737 163,807 Capital expenditures for utility plant .. ... .. ... ..... ..... .. .... ...... .. ........ .............. ... . (1 40,665) (261 ,900)

Contributions in aid of construction and other reimbursements .. ... ... ...... .... .. . 9,062 18,864 Principal payments on long-term debt ........ .. ..... ............... .... ... .................. . (191 ,160) (284,710)

Interest payments on long-term debt .. ........... .. .... ....... .. ............ ............ .. ... . (76,920) (77,776)

Interest paid on defeasance debt ... .... ........... .......... ............ .... .... .......... .. .. . (1,1 07) (10,194)

Principal payments on notes and credit agreements ............ .... ........ .... ... ... . . (1 27,449) (1 42,583)

Interest payments on notes and credit agreements ... ...... ......... .... ............... . (3,554) (2,145)

()ther non-operating revenues ......... ......................... .. ........... ... ............. ... . 3,515 3,445 Net cash used in capital and related financing activities ..... ..... .... ........... . {332,584) (238,416)

Net increase (decrease) in cash and cash equivalents ....................... ... . (74,925) 17,669 Cash and cash equivalents, beginning of year .... ............ ... ............... ........... .. . . 102,729 85,060 Cash and cash equivalents, end of year .. ......................... ................. ............. . $ 27 804 $ 102,729 Reconciliation of Operating Income to Cash Provided By Operating Activities:

Operating income ............. ............ ........ ....................................... .............. . $ 11 2,711 $ 11 3,282 Adjustments to reconcile operating income to net cash provided by operating activities:

Depreciation and amortization .......... ......... ........ .... .............................. . 122,559 133,666 Uldistributed net re\letlue - The Energy Authority ................................. . 108 648 Decormissioning, net of customer conbibutions ................................... . 14,006 21,429 Amortization of nuclear fuel ................................................................. . 43,490 40,754 Changes in assets and liabilities v.hich (used) provided cash:

Receivables, net ............................................................................. 5,409 (10,911 )

Fossil fuels .................................................................................... . 356 (4 ,285)

IIAaterials and supplies ..................................................................... 2,996 2,790 Prepayments and other current assets ............................................ . 443 1,022 Olher long-term assets .................................................................... . 938 935 Deferred outflows .......................................................................... . (45,654)

Accounts payable and accrued payments to relail COffflUlities ......... . (11,275) 19,122 lk1earned re,,ienues .......... ............. . ............. ................................... . 38,217 (7,408)

Olher deferTed inflows .................................................................... . 33,404 (14 ,342)

Olher liabilities ................................................................................ 1,735 2,663 Net cash provided by operating acti\ities ............................................... $ 3652097 $ 253µ111 Supplemel Ital .V thl-Cash Capital Acti\ities:

Change in utiily plant adcitions in accool1ls payable .................................. . $ (10i768l $ 42273 The accompanying notes to financial statements are an integral part of these statements .

Finaincia~ R~pont

NOTES TO FINANCIAL STATEMENTS

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES :

A. Organization -

Nebraska Public Power District ("District"), a public corporation and a political subdivision of the State of Nebraska, operates an integrated electric utility system which includes facilities for the generation , transmission ,

and distribution of electric power and energy to its Retail and Wholesale customers . The control of the District and its operations is vested in a Board of Directors ("Board") consisting of 11 members popularly elected from districts comprising subdivisions of the District's chartered territory. The Board is authorized to establish rates.

B. Basis of Accounting -

The financial statements are prepared in accordance with Generally Accepted Accounting Principles ("GAAP") for accounting guidance provided by the Governmental Accounting Standards Board (" GASS") for proprietary funds of governmental entities. In the absence of established GASS pronouncements, other accounting literature is followed including guidance provided in the Financial Accounting Standards Board ("FASS") Accounting Standards Codification ("ASC") .

The District applies the accounting policies established in the GASB codification Section Re10, Regulated Operations. This guidance permits an entity with cost-based rates and Board authorization to include revenues or costs in a period other than the period in which the revenues or costs would be reported by an unregulated entity.

C. Revenue-Retail and wholesale revenues are recorded in the period in which services are rendered. Revenues and expenses related to providing energy services in connection with the District's principal ongoing operations are classified as operating. All other revenues and expenses are classified as non-operating and reported as investment and other income or debt and other expenses on the Statements of Revenues, Expenses and Changes in Net Position.

D. Cash and Cash Equivalents -

The operating fund accounts are called Revenue Funds. There is a separate investment account for the Revenue Funds. The District reports highly liquid investments in the Revenue Funds with an original maturity of three months or less to be cash and cash equivalents on the balance sheet, except for these type of investments in the Revenue Funds investment account. Cash and cash equivalents in the investment accounts for the Revenue Funds and the Special Purpose Funds are reported as investments on the balance sheet.

E. Fossil Fuel and Materials and Supplies -

The District maintains inventories for fossil fuels and materials and supplies which are valued at average cost.

Obsolete inventory is expensed and removed from inventory.

F. Utility Plant, Depreciation, Amortization, and Maintenance -

Utility plant is stated at cost, which indudes property additions, replacements of units of property and bettennents.

The Distrid charges maintenance and repairs, induding the cost of renewals and replacements of minor items of property, to maintenance expense accounts when incurred. Upon retirement of property subject to depreciation, the cost of property is removed from the plant accounts and charged to the reserve for depreciation, net of salvage.

The O"sbict reoords depreciation over the estimated useful life of the property primarily on a straight-line basis.

Depreciation on utility plant was approximately 2.3% and 2.6% for the years ended December 31 , 2017 and 2016.

The Distrid had fully depreciated utility plant, primarily related to Cooper Nuclear Station r cNSm), which was still in service of $978.1 m*llion and $927.5 million as of December 31, 2017 and 2016, respectively.

The Oistrid has long-term Professional Retail Operations r PROm) Agreements with 79 mun*apalities for certain retail eledric distribution systems. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay for normal property additions during the tenn of the agreements.

The Oistrid recorded provisions, net of retirements, for amortization of these plant additions of $7.5 million and Finm10ia~ R~}iHilTt 32

$5.9 million in 2017 and 2016, respectively, which was included in depreciation and amortization expense. These plant additions, which were fully depreciated, totaled $191 .8 million and $185.6 million as of December 31 , 2017 and 2016 , respectively.

G. Allowance for Funds Used During Construction ("AFUDC'J -

This allowance, which represents the cost of funds used to finance construction , is capitalized as a component of the cost of the utility plant. The capitalization rate depends on the source of financing . The rate for construction financed with revenue bonds is based upon the interest cost of each bond issue less interest income.

Construction financed on a short-term basis with tax-exempt commercial paper ("TECP"}, tax-exempt revolving credit agreement ("TERCA"}, or taxable revolving credit agreement ("TRCA") is charged a rate based upon the projected average interest cost of the related debt outstanding. The TECP program was terminated in 2017 and replaced with the TERCA. For the periods presented herein, the AFUDC rates for construction funded by revenue bonds varied from 2.2% to 4.9%. For construction financed on a short-term basis, the rate was 1.0% for 2017 and 2016.

H. Nuclear Fuel -

Nuclear fuel inventories are included in utility plant. The nuclear fuel cycle requirements are satisfied through the procurement of raw material in the form of natural uranium, conversion services of such material to uranium hexafluoride, uranium hexafluoride that has already been converted from uranium , enrichment services, and fuel fabrication and related services. The District purchases uranium and uranium hexafluoride on the spot market and carries inventory in advance of the refueling requirements and schedule. Nuclear fuel in the reactor is being amortized on the basis of energy produced as a percentage of total energy expected to be produced. Fees for disposal of fuel in the reactor are being expensed as part of the fuel cost.

I. Unamortized Financing Costs -

These costs include issuance expenses for bonds which are being amortized over the life of the respective bonds using the bonds outstanding method. Deferred unamortized financing costs associated with bonds refunded are amortized using the bonds outstanding method over the shorter of the original or refunded life of the respective bonds. Regulatory accounting, GASS codification section Re10, Regulated Operations, is used to amortize these costs over their respective periods.

J. Asset Retirement Obligations -

Asset retirement obligations (" ARO") represent the best estimate of the current value of cash outlays expected to be incurred for legally enforceable retirement obligations of tangible capital assets. Regulatory accounting, GASB codification section Re10, Regulated Operations, is used to recognize these costs consistent with the rate treatment.

K. Other Postemployment Benefits ("OPEB'J -

For purposes of measuring the net OPES liability, deferred outflows of resources and deferred inflows of resources related to OPEB, and OPEB expense, information about the fiduciary net position of the District's Postemployment M edical and Life Benefits Plan r Plan") and additions to/deductions from the Plan's fiduciary net position have been determined on the same basis as they are reported by the Plan. For this purpose, the Plan recognizes benefit payments when due and payable in accordance with the benefit terms. Investments are reported at fair value, except for certain investments in real estate which are reported at net asset value.

L. Auction Revenue Rights and Transmission Congestion Rights-The District uses Auction Revenue Rights rARR") and Transmission Congestion Rights f 'TCR") in the Southwest Power Pool r sPP") Integrated Market to hedge against transmission congestion charges. These financial instruments were primarily designed to allow firm transmission rustomers the opportunity to offset price differences due to transmission congestion costs between resources and loads. Awarded ARR provide a fixed revenue stream to offset congestion costs. TCR can be acquired through the conversion of ARR or purchases from SPP auctions or secondary market trades.

Financial R~p(i)nt

M. Deferred Outflows of Resources and Deferred Inflows of Resources -

Deferred outflows of resources are consumptions of assets that are applicable to future reporting. Regulatory accounting is used for ARO. The ARO deferred outflow is the difference between the related liability amount and rate collections. The cost of refunded debt is the difference in the reacquisition price and the net carrying amount of the refunded debt in an advance refunding. Deferred outflows related to OPEB include contributions made during the current year and actuarial experience losses.

Deferred inflows of resources are acquired assets that are applicable to future reporting periods and consist of regulatory liabilities for unearned revenues and other deferred inflows. Other deferred inflows include Department of Energy ("DOE") settlements, nuclear fuel disposal collections, CNS outage collections, OPEB actuarial experience gains, a settlement for termination of a participation power sales agreement, non-nuclear decommissioning collections and a sales tax refund from the State of Nebraska for the construction of a renewable energy facility.

The District is required under the General Revenue Bond Resolution ("Resolution") to charge rates for electric power and energy so that revenues will be at least sufficient to pay operating expenses, aggregate debt service on the General Revenue Bonds, amounts to be paid into the Debt reserve fund and all other charges or liens payable out of revenues. In the event the District's rates for wholesale service result in a surplus or deficit in revenues during a rate period, such surplus or deficit, within certain limits, may be retained in a rate stabilization account. Any amounts in excess of the limits will be taken into account in projecting revenue requirements and establishing rates in future rate periods. Such treatment of wholesale revenues is stipulated by the District's long-term wholesale power supply contracts. The District accounts for any surplus or deficit in revenues for retail service in a similar manner.

The following table summarizes the balance of Unearned revenues as of December 31 , 2017 and 2016 and activity for the years then ended (in OOO's) :

2017 2016 Uiearned re1.e1ues, beginning of year ... ............. ................. ........ .... .... ............ . . $ 168,710 $ 176,118 Surpluses ..... ... .... .... ..... ..... .. ... ..... ..... ...... ..... ..... ........ .. ...... .. ..... ...... ... .... ..... ... ... . 44,888 9,992 Use of prior period rate stabilization funds in rates .. ....... ... ... .. ... .. ........ ... ........... . . (6,671) (17,400)

Uiearned revenues, end of year .. .. .... .... .. ............... ... .... .............. ...... ............... . $

The DOE settlement regulatory liability was established for the reimbursement from the DOE for costs incurred by 206,927 $ 168,710 the District in conjunction with the disposal of spent nudear fuel from CNS. Details of the District's DOE settlement are induded in Note 12 in the Notes to Financial Statements.

The District indudes in rates the costs associated with nuclear fuel disposal. Such collections were remitted to the DOE under the Nuclear Waste Policy Act until the DOE adjusted the spent fuel disposal fee to zero, effective May 16, 2014. The Board authorized the use of regulatory accounting for the continued collection of these costs.

This approach ensures costs are recognized in the appropriate period with rustomers receiving the benefits from CNS paying the appropriate costs. The expense for spent nuclear fuel disposal is recorded at the previous DOE rate based on net electricity generated and sold and the regulatory liability will be eliminated when payments are made for spent nuclear fuel disposal. Additional details of the District's DOE spent nuclear fuel collections are included in Note 12 in the Notes to Financial Statements.

34

Beginning in 2017, the District began collecting revenues for the costs of the 2018 CNS refueling and maintenance outage. This regulatory liability was included in Other deferred inflows on the Balance Sheets and will be amortized through revenue during 2018 , the year of the outage.

The District and Lincoln Electric System ("LES") executed a termination and release agreement in May 2017 for the Sheldon Station Participation Power Agreement. The Board authorized the use of regulatory accounting for the settlement payment as the term of the Agreement was for the life of Sheldon Station ("Sheldon"). This regulatory liability was included in Other deferred inflows on the Balance Sheets and will be eliminated as revenues from the settlement payment are incorporated in future rates.

The District began collecting in rates for non-nuclear decommissioning costs in 2017. The collections for assets which do not have a legally required reti rement obligation are recorded as a regulatory liability, instead of an ARO , and are included in Other deferred inflows on the Balance Sheets.

The following table summarizes the balance of Deferred outflows of resources as of December 31 , 2017 and 2016 (in OOO's):

2017 2016 Asset retirement obligation ...... ..... ............... .. ... ..... ........ ........... ..... ... ...... ............ $ 222,369 $ 219,378 Unamortized cost of refunded debt .................. ... .... .... .. ...... ........ .... ... ... ..... ...... .. . 38,430 42,664 OPES contributions after the measurement date . .. ... .. .. .. .... .... .... ... .. . . . ... . ... . . .. . .. .. . . 28,290 74,658 Unamortized OPES losses for differences in actual and eiq:>ected earnings .. . .. ... .. . 3 ,283 3,862 Unamortized OPES losses for differences in actual and eiq:>ected e>q:>erience .. .. .... ____ 3._

,0_3_0_ 3,769

$ 295,402 $ 344,331 The following table summarizes the balance of Other deferred inflows of resources as of December 31, 2017 and 2016 (in OOO's) :

2017 2016 DOE settlements ....... ... .... .. .. .. ................. .... .. .. ... .. ... . .. ... . ........ ..... .. .... ... ....... ... ... $ 66,227 $ 82,664

~clear fuel disposal colections ... ........................ ... ........................ ........... ........ 2 1,570 15,098 CNS outage colections ... .... .. ................ . .. . ....... .. ..... ........ ... ....... ... ...... .. .. .. ... .. .. .. 20,005 Unamortized OPEB gains for differences in actual and eiq:>ected e>Cperience ........ . 16,475 Settlement for temination of participation power sales agreement ......................... 10,500 Non-nuclear decormissioning colections ....... ......... ..... ......... ... ... ..... .................. 5,444 Renewable energy facility sales lax refund .......................................................... _ _ _4~,5_0_3_ 4,786

$ 144,724 $ 102,548 N. Net Position -

Net position is made up of three components: Net investment in capital assets, Restricted, and Unrestricted.

Net investment in capital assets consisted of utility plant assets, net of accumulated depreciation and reduced by the outstanding balances of any bonds or notes that are attributable to the acquisition, construction, or improvement of these assets. This component also included long-term capacity contracts, net of the outstanding balances of any bonds or notes attributable to these assets.

Restricted net position consisted of the Primary account in the Debt reserve funds that are required deposits under the Resolution and the Decommission*ng funds, net of any related liabilities.

Unrestricted net position consisted of any remaining net position that does not meet the definition of Net investment in capital assets or Restricted and is used to provide for working capital to fund norH1udear fuel and inventory requirements, as well as other operating needs of the District.

Financial R!e,p>@lit

0 . Use of Estimates -

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period . Actual results could differ from those estimates.

P. Recent Accounting Pronouncements -

GASS Statement No. 87, Leases, was issued in June 2017. This Statement will bring substantially all leases for lessees on to the balance sheet. For operating leases, lessees will be required to recognize an asset for the right to use the leased item and a corresponding lease liability. Lease liabilities will be considered long-term debt and lease payments will be capital financing outflows in the cash flow statement. In the activity statement, lessees will no longer report rent expense for operating-type leases, but will instead report interest expense on the liability and amortization expense related to the asset. For lessors, the accounting will mirror lessee accounting. Lessors will recognize a lease receivable and a corresponding deferred inflow of resources (with certain exceptions) , while continuing to report the asset underlying the lease. Interest income associated with the receivable will be recognized using the effective interest method. Lease revenue will arise from amortiz ing the deferred inflow of resources in a systematic and rational manner over the lease term . The requirements of this Statement are effective for reporting periods beginning after December 15, 2019, with earlier application encouraged.

Management is currently evaluating the impact of this statement.

GASS Statement No. 85, Omnibus 2017, was issued in March 2017. This Statement addresses practice issues that were identified during implementation and application of certain GASS statements induding statements on OPES. This Statement provides clarification for the presentation of payroll-related measures in required supplementary information for purposes of reporting by OPES plans and employers that provide OPES. This Statement requires the disdosure of covered-employee payroll by the employer if contributions to the OPES plan are not based on a measure of pay. Covered-employee payroll is defined as the payroll of employees that are provided with OPEB through the OPES plan. However, the financial statements for the OPES plan should not present any measure of payroll if contributions to the plan are not based on a measure of pay. This Statement is effective for fi scal years beginning after June 15, 2017. The District adopted this Statement in 2017 to coincide with its implementation of related guidance in GASS Statement No. 75, Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions. The OPES guidance was the only portion of this Statement with an impact on the District.

GASB Statement No. 84, Fiduciary Activities, was issued in January 2017. This Statement addresses accounting and financial reporting requirements for certain fiduciary funds in the basic financial statements. Governments with activities meeting the criteria are required to present a statement of fiduciary net position and a statement of changes in fiduciary net position. The requirements of this Statement are effective for reporting periods beginning after December 15, 2018. The implementation of this Statement will require the District to indude fiduciary statements with the statements for its business-type activities.

GASB Statement No. 83, Certain Asset Retirement Obligations, was issued in November 2016. This Statement addresses accounting and financial reporting requirements for certain AROs. This Statement imposes requirements in regards to the ARO liability recognition, measurement and specifics on when re-measurement shou d occur. This Statement also requires disclosures regarding the methods and assumptions used to estimate the ARO, the remaining useful life of capital assets associated with the liability, any governmental legal funding requirements, any assets restricted for payment and any minority share ARO liability. The requirements of this Statement are effective for reporting periods beginning alter June 15, 2018. The District previously reported AROs under the FASB guidance, which differs from the GASS guidance. The FASB guidance required measurement of the liability based on the present value of the asset's disposal costs whereas measurement under this GASB Statement is based on the best estimate of the current value of cash ouUays expected to be incurred. The FASB guidance required the recognition of a corresponding capital asset whereas the GASB Statement requires the recognition of a corresponding deferred outflow of resources. The District adopted this Statement in 2017 and uses regulatory accounting to align asset retirement costs with their related recognition in rates.

Financial epcmt 36

GASB Statement No. 75, Accounting and Financial Reporting for Postemployment Benefits Other Than Pensions, was issued in June 2015. The requirements of this Statement will improve accounting and financial reporting for OPEB. This Statement requires the liability for defined benefit OPEB (net OPEB liability) to be measured as the portion of the present value of projected benefit payments to be provided to current active and inactive employees that is attributed to those employees' past periods of service (total OPEB liability) , less the amount of the OPEB plan 's fiduciary net position. Enhanced disclosures and additional required supplementary information are also required under the Statement. This Statement is effective for fiscal years beginning after June 15, 2017. The District adopted this Statement in 2016 and deferred costs through regulatory accounting, to be amortized during the period in which they are recovered in rates. Additional disclosures related to OPEB are in Note 11.

2. CASH AND INVESTMENTS:

Investments are recorded at fair value with the changes in the fair value of investments reported as Investment income in the accompanying Statements of Revenues, Expenses, and Changes in Net Position. The District had unrealized net gains of $2.6 million and less than $0.1 million in 2017 and 2016, respectively.

The fair value of all cash and investments, regardless of classification on the Balance Sheets, were as follows as of December 31 (in OOO's):

2017 2016 Weighted Weighted Average Maturity Average Maturity Fair Value {Years} Fair Value {Years}

U.S. Treasury and government agency securities . . $ 998,148 4.7 $ 936,317 4.0 Corporate bonds .. ... . ..................... ........... .. ......... 169,051 9.3 181,438 9.6 Municipal bonds .. ... .... ... .. .. .... ..... .. ....... .... .... .. ...... 11 ,900 14.3 11 ,901 12.4 Cash and cash equivalents. ........................ ....... .. 134,326 0.1 129,261 Total cash and investments ........................ ...... $1 ,313,425 $1 ,258,917 Portfolio weighted average maturity ......................... ............ . 4.9 4.5 Interest Rate Risk - The investment strategy for all investments, except for the decommissioning funds, is to buy and hold securities until maturity, which minimizes interest rate risk. The investment strategy for decommissioning funds is to actively manage the diversification of multiple asset dasses to achieve a rate of return equal to or exceeding the rate used in the decommissioning funding plan model assumptions. Accordingly, securities are bought and sold prior to maturity to increase opportunities for higher investment returns.

Credit Risk - The District follows a Board-approved Investment Policy. This policy complies with state and federal laws, and the Resolution's provisions governing the investment of all funds. The majority of investments are direct obligations of, or obligations guaranteed by, the United States of America. Other investments are limited to investment-grade fixed income obligations.

Custodial Credit Risk - Cash deposits, ptjmarily interest bearing, are covered by federal depository insurance, pledged collateral consisting of U.S. Government Securities held by various depositories, or an irrevocable, nontransferable, unconditional letter of credit issued by a Federal Home Loan Bank.

Financial R~J!>@rt

The fair values of the District's Revenue and Special Purpose Funds as of December 31 were as follows (in OOO's):

The Revenue funds are used for operating activities for the District. Cash and cash equivalents in the Revenue funds are reported as such on the balance sheet, except cash and cash equivalents in the Revenue Fund investment account are reported as investments. The investment account for the Revenue funds included cash equivalents of $99.5 million and $20.9 million as of December 31 , 2017 and 201 , respectively.

2017 2016 Re-.enue funds - Cash and cash equivalents ......... ......... ...... .. .. .... ............... ... .. . $ 127,302 $ 123,678 Re-.enue funds - ln-.estrnents ... ... .. ....... .. .. ......... .......... .. ...... .. .... ....... .... ... ... ... ... ___4_3_9~,6_7_5_ 352,382

$ 566,977 $ 476,060 The Construction funds are used for capital improvements, additions, and betterments to and extensions of the District's system. The sources of monies for deposits to the construction funds are from revenue bond proceeds and issuance of short-term debt.

2017 2016 Construction funds - Cash and cash equivalents . .. .. . . .. . .. .. . . .. .. . . .. . .. . . . . . .. . . . .. .. . . . . . .. $ $ 25 Construction funds - ln-.estrnents ... ..... ... .... ...... .... ... .. .. ...... .. ..... ... .................. .... _ _ _54~ , 8_0_8_ 106,179

$ 54,808 $ 106,204 The Debt reserve funds, as established under the Resolution , consist of a Primary account and a Secondary account. The District is required by the Resolution to maintain an amount equal to 50% of the maximum amount of interest accrued in the current or any Mure year in the Primary account. Such amount totaled

$37.8 million and $38.7 million as of December 31 , 2017 and 2016, respectively. The Secondary account can be established at such amounts and can be utilized for any lawful purpose as determined by the District's Board.

Such account totaled $51 .0 million and $51 .3 million as of December 31 , 2017 and 2016, respectively.

2017 2016 Debt reserw funds - ln-.estrnents ........... .... ..... ... ...... .... ......... ...... .. ... .......... ...... _$ ____aa

__.7_64_ $ 90,032 The Employee Benefit funds consist of a self-funded hospital-medical benefit plan for active employees only as of December 31 , 2017 and 2016. The District pays 80% of the hospital-medical premiums with the employees paying the remaining 20% of the cost of such coverage. The self-funded hospital-medical benefit plan had funds of $1 .9 million and $4.9 million as of December 31 , 2017 and 2016, respectively. For additional infonnation on OPEB see Note 11 .

2017 2016 Erq>loyee benefit funds - Cash and cash equiwlents ......................... ................. $ 935 $ 1,843 Erq>loyee benefit funds - ln\eSbnents ............... .... ........................ .................... _ _ _ _999 __ 3,008

$ 1,934 $ 4,851 The Decommissioning funds are utilized to account for the invesbnents held to fund the estimated cost of decommissioning CNS when its operating license expires. The Decommissioning funds are held by outside trustees or wstodians in compliance with the decommissioning funding plans approved by the Board which are

nvested primarily in fixed income governmental securities.

2017 2016 Oeconmissioning funds - Cash and cash eq NBlents ........................................ $ 6,089 $ 3,715 Deconmssioning funds - lrneslrnents .............................................................. _ _ _ 594

~ ,853

__ 578,055

$ 600,942 $ 581,770 Finariiloial R!ep011t 38

3. FAIR VALUE OF FINANCIAL INSTRUMENTS:

Fair value is the exchange price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date.

GASB Statement No. 72 ("GASB 72"), Fair Value Measurement and Application, establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in an active market for identical assets or liabilities and the lowest priority to unobservable inputs. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels of fair value hierarchy defined in GASB 72 are as follows:

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The District's investments in cash and cash equivalents are included as Level 1 assets.

Level 2 - Pricing inputs are other than quoted market prices in the active markets included in Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. Level 2 inputs include the following :

quoted prices for similar assets or liabilities in active markets;

quoted prices for identical assets or liabilities in inactive markets;

inputs other than quoted prices that are observable for the asset or liability; or

inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 2 assets primarily include U.S. Treasury and government agency securities held in the Revenue funds and other Special Purpose Funds and U.S. Treasury and government agency securities, corporate bonds, and municipal bonds held in the Decommissioning funds.

Level 3 - Pricing inputs indude significant inputs that are unobservable and cannot be corroborated by market data. Level 3 assets and liabilities are valued based on internally developed models and assumptions or methodologies using significant unobservable inputs. The District currently does not have any Level 3 assets or liabilities.

The District performs an analysis annually to determine the appropriate hierarchy level dassification of the assets and liabilities that are included within the scope of GASB 72. Financial assets and liabilities are dassified in their entirety based on the lowest level of input that is significant to the fair value measurement There were no liabilities within the scope of GASB 72 as of December 31, 2017 and 201 6. The following tables set forth the District's financial assets that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31, (in OOO's):

2017 l...e\lel 2 l...e\lel 3 Tolal Rellenue and special purpose funds, eJdJding deconnissioning:

U.S. Treasury and gowemmentagency securities ............ . $ $ 584,246 $ $ 584,246 Cash and cash equivalents ............................ ................. .. 128,237 128,237 Decormissioning funds:

U.S. Treasury and gm,emment agency securities ............ . 413,902 413,902 Corporale bonds ........................................................... . 169,051 169,051 Municipal bonds ............................................................ . 11,900 11,900 Cash and cash eqt.riiwlern'ls ..*...*..**.*....*..............*.....*...*.*. 6,089 6,089

$ 134,326 $1,179,099 $ $ 1,313,,425 Fi:ina,noial Rep<imt

2016 Level 1 Level2 Level 3 Total Revenue and special purpose funds, excluding decommissioning:

U.S. Treasury and government agency securities ............ . $ $ 551 ,602 $ $ 551 ,602 Cash and cash equivalents .. .. .. .. ... .... ... .. ... .... ............... ... . 125,546 125,546 Decommissioning funds :

U.S. Treasury and government agency securities ...... ...... . 384,715 384,715 Corporate bonds .... ..... ... .......................... ...... ..... .... ..... . . 181 ,438 181 ,438 Municipal bonds .... ... .... ..... ........ ....... ..... .......... ..... ..... .. .. . 11,901 11 ,901 Cash and cash equivalents ...... ... ........ .. ..... ...... ............... . 3,715 3,715

$ 129,261 $1 ,129,656 $ $1 ,258,917

4. UTILITY PLANT:

Utility plant activity for the year ended December 31 , 2017, was as follows (in OOO's) :

December 31 , December 31 ,

2016 Increases Decreases 2017 Nondepreciable utility plant Land and improvements. ............... ... ............ $ 74,138 $ 1,124 $ (68) $ 75,194 Construction in progress ........ ... .. .... .... ......... 135,853 120,399 (122,737) 133,515 Total nondepreciable utility plant .. ..... .... ... 209,991 121 ,523 (122,805) 208,709 Nuclear fuer .. .. .... ............. ... ......... ... ...... .... ... .. . 197,730 11 ,979 (43,490) 166,219 Depreciable utility plant Generation - Fossil ... .. .... .... .... ......... ... ... ... .. 1,621 ,919 33,992 (5,754) 1,650,157 Generation - Nuclear .. ..... ... ......................... 1,314,210 14,978 (7,182) 1,322,006 Transmission .. ............. .... ... ...... .............. .. . . 1,254,421 47,223 (5,011) 1,296,633 Distribution ..... .. .. ... ........ ... .. ....... ... .......... ... . 226,563 9,291 (1 ,409) 234,445 General ... .... ..... ... ... ........ ...... ....... ... ....... ..... 344,578 15,169 (9,812) 349,935 Total depreciable utility plant 4,761 ,691 120,653 (29,168) 4,853,176 Less r e ~ for depreciation ........ .. ..... ............ . (2,573,645) (113,729) 29,168 (2,658,206)

Depreciable utility plant, net .. .............. .... . 2,188,046 6,924 2,194,970 Utility plant acli'Aly, net ..... ............... ................. . $ 2,595,767 $ 140,426 $ (166,295) $ 2,569,898

Nuclear ire! decreases represented amortization of $43.5 million.

Finanoial ~epornt

Utility plant activity for the year ended December 31 , 2016, was as follows (in OOO's) :

December 31 , December 31 ,

2015 Increases Decreases 2016 Nondepreciable utility plant:

Land and improvements ........... ... .... .... ... .. .... $ 64,370 $ 9,780 $ (12) $ 74,138 Construction in progress .................. ..... .... ... 209,626 180,237 (254,010) 135,853 Total nondepreciable utility plant .............. 273,996 190,017 (254,022) 209,991 Nuclear fuel* .... ..... ................ ..... ..... ..... ... ... ...... 168,420 70,064 (40,754) 197,730 Depreciable utility plant Generation - Fossil ............. .... .. .. .. ... ..... ... .... 1,573,880 65,818 (1 7,779) 1,621 ,919 Generation - Nuclear .. ...... ......... ...... .. .... ...... 1,384,031 68,415 (1 38,236) 1,314,210 Transmission ........... ..... ... ... .. ........ ..... .. ... .... 1,172,108 86,994 (4,681 ) 1,254,421 Distribution ............................................... .. 221 ,791 6,336 (1 ,564) 226,563 General ....... ...... .......... ... ....... ..... .. ...... ........ 334,836 13,528 (3,786) 344,578 Total depreciable utility plant 4,686,646 241,091 (1 66,046) 4,761 ,691 Less reserve for depreciation .. .. .... ..... ....... ...... .. (2,620,091 ) (11 9,600) 166,046 (2,573,645)

Depreciable utitity plant, net ..................... 2,066,555 121,491 2,188,046 Utility plant acti vity, net .. ... ............. ...... ..... .... .. .. $ 2,508,971 $ 381,572 $ (294,776) $ 2,595,767

Nuclear fuel decreases represented amortization of $40.8 million.

5. LONG-TERM CAPACITY CONTRACTS:

Long-term capacity contracts indude the District's share of the construction costs of Omaha Public Power District's ("OPPD") 664 megawatt ("MW) Nebraska City Station Unit 2 ("Nc2*) coal-fired power plant. The District has a participation power agreement with OPPD for a 23.7% share of the power from this plant. NC2 began commercial operation on M ay 1, 2009, at which time the District began amortizing the amount of the capacity contract associated with the plant on a straight-line basis over the 40-year estimated useful life of the plant.

Accumulated amortization was $39.9 million and $35.4 million as of December 31, 2017 and 201 6, respectively.

The unamortized amount of the plant capacity contract was $139.2 million and $143.7 million as of December 31, 2017 and 2016, respectively, of which $4.4 million was induded in Prepayments and other current assets as of December 31, 2017 and 201 6. The District's share of NC2 working capital was also indudecl in Prepayments and other current assets and was $6.5 million as of December 31, 2017 and 201 6.

long-tenn capacity contracts also indude the District's purdiase of the capacity of a 50 MW hydroelectric generating facility owned and operated by The Central Nebraska Public Power and Irrigation District r c entral").

The District is amortizing the contract on a straight-line basis over the 40-year estimated useful life of the facility.

Accumulated amortization was $66.6 million and $64.3 million as of December 31 , 2017 and 2016, respectively.

The unamortized amount of the Central capacity contract was $20.1 million and $22.4 million as of December 31 ,

2017 and 2016, respectively, of whidi $2.3 million was induded in Prepayments and other cunent assets as of December 31 , 2017 and 2016.

The District has an agreement whereby Central makes available all the production of 1he facility and the District pays a I costs of operating and maintain*ng the facility plus a diarge based on the amount of energy delivered to the District. Costs of $1 .8 million and $2.5 million in 2017 and 2016, respectively, are induded *n Power purchased in the accompanying Statements of Revenues, Expenses, and Changes in Net Position.

Financial ReJ!l<ill11

6. INVESTMENT IN THE ENERGY AUTHORITY:

The District has an investment in The Energy Authority ("TEA"), a nonprofit corporation headquartered in Jacksonville, Florida, and incorporated in Georgia. TEA provides public power utilities access to dedicated resources and advanced technology systems. The District's interest in TEA was 16.67% as of December 31 ,

2017 and 2016, respectively. In addition to the District, the following utilities have interests of 16.67% each as of December 31 , 2017 and 2016: American Municipal Power, Inc. ; JEA (Florida) ; Municipal Energy Authority of Georgia; and South Carolina Public Service Authority (a.k.a. Santee Cooper). The following utilities have interests in TEA of 5.56% each as of December 31 , 2017 and 2016: City Utilities of Springfield, Missouri; Cowlitz County Public Utility District (Washington) and Gainesville Regional Utilities (Florida).

Such investment was $6.2 million and $6.4 million as of December 31 , 2017 and 2016, respectively. TEA's revenues and costs are allocated to members pursuant to Settlement Procedures under the Operating Agreement. TEA provides the District gas contract management services and is the District's market participant in SPP's Integrated Market.

The District is obligated to guaranty, directly or indirectly, TEA's electric trading activities in an amount up to

$78.9 million plus attorney's fees which any party claiming and prevailing under the guaranty might incur and be entitled to recover under its contract with TEA. Generally, the District's guaranty obligations for electric trading would arise if TEA did not make the contractually required payment for energy, capacity, or transmission which was delivered or made available or if TEA failed to deliver or provide energy, capacity, or transmission as required under a contract.

The District's exposure relating to TEA is limited to the District's investment in TEA, any accounts receivable from TEA, and trade guarantees provided to TEA by the District. Upon the District making any payments under its electric guaranty, it has certain contribution rights with the other members of TEA in order that payments made under the TEA member guaranties would be equalized ratably, based upon each member's interest in TEA and the guarantees they have provided. The District increased its guarantee to TEA in March 2018 from $28.9 million to $78.9 million. The additional $50.0 million of guaranty is to support additional trading for TEA on behalf of its continued business growth. After such contributions have been effected, the District would only have recourse against TEA to recover amounts paid under the guaranty. The term of this guaranty is generally indefinite, but the District has the ability to terminate its guaranty obligations by causing to be provided advance notice to the beneficiaries thereof. Such termination of its guaranty obligations only applies to TEA transactions not yet entered into at the time the termination takes effect. The District has no liabilities for these guarantees as of December 31 ,

2017 and 2016.

Financial statements for TEA may be obtained at The Energy Authority, 301 W. Bay Street, Suite 2600, Jacksonville, Florida, 32202 .

7. DEBT:

The following table summarizes the debt balances, net of current maturities, as of December 31 , 2017 and 2016, and activity for 2017 (in OOO's):

Principal AmountsOue December 31, December 31, Wrlhin Ole 2016 Increases Decreases 2017 Year Re~ue bonds ................. ..... .... $ 1,678,844 $ 96,957 $ (227,532) $ 1,548,269 $ 98,205 Conne"cial paper notes ............. 74,000 11 ,320 (85,320)

Rewhing credit agreementsh 1 ..... 188,924 87,417 (42,129) 234,212 165,212

---~--

Tolal long-term debt actNty .... $ 1,941,768 $ 195,694 $ (354,981) $ 1,782,481 $ 263,417 FinaMial Rep@rt

.~ ,1

~ :.:>;/

' ' ~ ~; *. ,."~~ .: };~ ~*- ,:~;< .:.~:~¢rbt~

The following table summarizes the debt balances, net of current maturities, as of December 31 , 2016 and 2015, and activity for 2016 (in OOO's) :

Principal Amounts Due December 31 , December 31 , Within One 2015 Increases Decreases 2016 Year Re\enue bonds ... ...... .......... ...... $ 1,596,972 $ 354,776 $ (272,905) $ 1,678,844 $ 81 ,250 Commercial paper notes ............ 83,000 88,365 (97,365) 74,000 74,000 Re1.0I\Ang credit agreements ...... . 158,700 75,443 (45,219) 188,924 Total long- term debt acti\Aty .. $ 1,838,672 $ 518,584 $ (415,489) $ 1,941 ,768 $ 155,250 Revenue Bonds On January 1, 2018, the District called the remaining outstanding General Revenue Bonds, 2012 Series C, with a principal amount that aggregated $4.2 million as of December 31 , 2017. The District plans to issue additional revenue bonds in 2018 to refund existing debt and to fund a portion of OPEB costs for customers under the 2016 Contracts. Congress passed the Tax Cuts and Jobs Act ("Act") in December 2017, which eliminated the use of tax-exempt advanced refunding transactions.

In April 2017, the District issued General Revenue Bonds, 2017 Series A and 2017 Series B, in the amount of

$86.0 million to refund the General Revenue Bonds, 2007 Series B. The refunding reduced total debt service payments over the life of the bonds by $11 .8 million, which resulted in present value savings of $10.0 million. Also in April 2017, the District entered into an escrow deposit agreement in conjunction with the refunding of certain of the General Revenue Bonds, 2007 Series B, having maturity dates ranging from January 1, 2018 through January 1, 2028.

Congressional action reduced the 35% interest subsidy, pursuant to the requirements of the Balanced Budget and Emergency Deficit Control Act of 1985, as amended, on the District's General Revenue Bonds, 2009 Series A (Taxable Build America Bonds) and 2010 Series A (Taxable Build America Bonds). Reductions were 6.9% and 6.8% for fiscal years ended September 30, 2017 and 2016, respectively.

In November 2016, the District issued General Revenue Bonds, 2016 Series C and 201 6 Series 0 , in the amount of $113.5 million to finance the costs of certain generation and transmission capital projects and to refund a portion of Commercial Paper Notes, Series A. The District also issued in November 2016, General Revenue Bonds, 2016 Series E (Taxable), in the amount of $56.1 million to fund a portion of OPES costs for customers under the 2016 Contracts.

In February 201 6, the District issued General Revenue Bonds, 201 6 Series A and 2016 Series B, in the amount of

$139.2 million to advance refund $138.9 million of bonds and refund $16.5 million of commercial paper notes. The refunding reduced total debt service payments over the life of the bonds by $29.8 million, whidl resulted in present value savings of $20.8 million.

Also in February 201 6, the District entered into an escrow deposit agreement *n conjunction with the advanced refunding of certain of the:

General Revenue Bonds, 2007 Series B, having maturity dates ranging from January 1, 2026 through January 1, 2037

General Revenue Bonds, 2008 Series B, having maturity dates ranging from January 1, 2024 through January 1, 2041

General Revenue Bonds, 201 2 Series C, maturing on January 1, 2025 through January 1, 2026 In January 2016, the Oisbid issued TECP in the amount of $43.6 mil *on to refund a portion of the General Revenue Bonds, 2005 Series C and the General Revenue Bonds, 2006 Series A.

Financial Nep011t

Certain of the General Revenue Bonds, from the following series , with outstanding principal am ounts that aggregate $324.1 million as of December 31, 2017, were legally defeased and are no longer outstanding: 2008 Series B and 2012 Series C.

Debt service payments and principal payments of the General Revenue Bonds as of December 31 , 2017, are as follows (in OOO's) :

Debt Service Principal Year Payments Payments 2018 .... ......... .. .. ... .. ..... .. ..... .......... . $ 170,403 $ 98,205 2019 ** ************* ***************** ******* *****

146,856 79,320 2020 ........ .. ... .. ... ..... ...... ... ... .. ... ... . . 146,760 82,915 2021 ....... .... .... ... ... ....... ... .. ..... ...... . 143,968 84,085 2022 ..... .... .... .. .. ..... .. ....... ... ... .... .. . . 136,550 80,825 2023-2027 .... .... ... .................. ... .... . 637,780 417,475 2028-2032 ... .. ..... .... .... ... ... ............ . 469,091 341,640 2033-2037 ... .. .. .... .. ......... .. .. ...... .... . 270,720 218,700 2038-2042 ..... .. .. .... ........ .. ... ... ....... . 103,408 88,685 2043-2045 .. ..... ...... ..... ... ............... . 15,962 14,895 Total Payments ..... ... ........... ... .. ..... . $ 2,241 ,498 $ 1,506,745 The fair value of outstanding revenue bonds was determined using currently published rates. The fair value was estimated to be $1 ,737.9 million and $1 ,750.1 million as of December 31 , 2017 and 2016, respectively.

Commercial Paper Notes and Line of Credit Agreement The District terminated its Commercial Paper Notes ("Notes") program and the Line of Credit Agreement that supported the payment of the principal outstanding on the Notes after execution of the Tax-Exempt Revolving Credit Agreement ("TERCA") in 2017.

Tax-Exempt Revolving Credit Agreement The District entered into a TERCA with two commercial banks to provide for loan commitments to the Disbict up to an aggregate amount not to exceed $150.0 million on June 29, 2017. The TERCA replaced the Commercial Paper Notes and Line of Credit Agreement The District had an outstanding balance under the TERCA of $69.0 million as of December 31 , 2017. The outstanding amount is anticipated to be retired by future collections through electric rates and the issuance of revenue bonds. The carrying value of the TERCA approximates market value due to the short-term nature of the agreements. The TERCA terminates on June 29, 2020.

Taxable Revolving Credit Agreement The District has entered into a Taxable Revolving Credit Agreement ("TRCA*) with two commercial banks to provide for loan commitments to the District up to an aggregate amount not to exceed $200.0 million. The TRCA allows the District to increase the loan commitments to $300.0 million. The District had outstanding balances under the TRCA of $165.2 milllon and $188.9 million, as of December 31 , 2017 and 2016, respectively. The outstanding amount is anticipated to be retired by future collections through electric rates. The carrying value of the taxable revolving credit agreements approximates market value due to the short-term nature of the agreements. The TRCA was renewed on J y 31, 2015, and terminates on July 30, 2018.

Financial Ecep0rt 44

Revenue bonds consist of the follolNing (OOO's except interest rates):

December 31 , Interest Rate 2017 2016 General Revenue Bonds:

2007 Series B:

Serial Bonds: 2016-2026 .... ...... ...... ....... ..... .. . 4.375% - 5.00% $ $ 97,415 Term Bonds: 2027-2031 .. .... ......... .. ......... .. .. . 4 .65% 9,620 2008 Series B Serial Bonds 2017-2029 .. .............. ... . 4 .00% - 5.00% 10,700 2009 Series A Taxable Build America Bonds:

Term Bonds: 2019-2025 .. .... ........... ....... ... .. . . 6.606% 17 ,465 17,465 2026-2034 ... ... ........... ..... .... .... . 7.399% 32,890 32,890 2009 Series C Serial Bonds 2017-2019 ....... .... ...... .. . 4 .00% - 4.25% 2,535 4,605 2010 Series A Taxable Build America Bonds:

Serial Bonds: 20 19-2024 .................. ....... .. ... . 3.98% - 4 .73% 31,875 31,875 Term Bonds: 2025--2029 .... ..... ..... ... ..... ... .... . . 5.323% 27,985 27,985 2030-2042 ... ........... ... ...... ....... . 5.423% 54,190 54,190 2010 Series B Taxable Serial Bonds 20 16-2020 ....... . 3.358% - 4 .1 8% 2,755 3,600 2010 Seri es C:

Serial Bonds: 2017-2025 .... ..... .... .... ....... ...... . 3.00% - 5.00% 40,685 48,760 Term Bonds: 2026-2030 ... ... .... ..... ... .. ... .. .... . . 4.00% 6 ,165 6,165 2026-2030 ............. ..... ............ . 5.00% 14 ,180 14,180 2012 Series A Serial Bonds 2017-2034 ..... ......... .. ... . 3.00% - 5.00% 182,145 190,410 2012 Seri es 8 :

Serial Bonds: 2017-2032 ......... ... .. .. ....... ....... . 2.00% - 5.00% 83,330 92,320 Term Bonds: 2033-2036 ...... ...... .. ......... .... ... . 3.625% 2,320 2,320 2037-2042 *** **** ***** ** ** ******* **** **** 3.625% 4 ,155 4,155 201 2 Series C Seri al Bonds 2017-2028 ....... ... .... ... .. . 3.00% - 5.00% 11 ,045 2013 Seri es A Serial Bonds 2017-2033 ... ................ . 3.00% - 5.00% 77,480 91,100 2014 Seri es A:.

Serial Bonds: 2017-2038 .. ... ....... .......... .. .... .. . 2.00% - 5.00% 151,01 5 153,630 Term Bonds: 2039-2043 .... ... .. .... ...... ...... ..... . 4 .00% 31,650 31,650 2039-2043 ... .... ....... ....... .. ...... . . 4.1 25% 1,945 1,945 201 4 Series C Serial Bonds 2017-2033 ................... . 4 .00% - 5.00% 138,130 143,025 201 5 Series A- 1 Serial Bonds 2022-2034 .. ... .. ..... ... . . 3.00% - 5.00% 119,400 11 9,400 201 5 Series A-2:

Serial Bonds: 2017-2034 .... ............ .... ... ....... . 3.00% - 5.00% 56,045 56,485 Term Bonds: 2035-2039 ..... ......... ...... ......... . . 5.00% 46,205 46,205 2016 Series A:.

Serial Bonds: 2018-2035 ... ..... .............. ... ..... . . 3.125% - 5.00% 65,210 65,210 Term Bonds: 2036-2040 ....... ....................... . 5.00% 5,595 5,595 2016 Series B:

Serial Bonds: 2018-2036 ....... ******** ......... ...... . 5.00% 67,255 67,255 Term Bonds: 2037-2039 ... ................... ........ . 5.00% 1, 165 1,165 2016 Series C Serial Bonds 2017- 2035 ................... . 3.00% - 5.00% 67,025 70,685 2016 Series D:

Serial Bonds: 2017- 2035 ................................ 2.00% - 5.00% 20,960 21,170 Term Bonds: 2036-2040 ................................ 5.C)0% 9,505 9,505 2041-2045 ............................... 5.()()% 12 ,140 12,140 2016 Series E Taxable Serial Bonds 2022- 2033 ........ 2.337% - 3.567% 56,050 56050 2017 Series A Serial Bonds 2017- 2027 ................... . 200% - 5.00"k 18,125 2017 Series B Serial Bonds 2017-2027 ................... . 5.00% 59,170 Total par amount of revenue bonds ...................................................................... 1,506,745 1,6 11 ,915 l.klarnorlized prenil.ffl'I net or discount .............................................................. _ _ 13_9""",7_29

_ 148,179 1,646,474 1,760,094 Less - Cla"Tenl rnalurities of re\lleflUe bonds ..................................................... - ~ <98 ~ ,2_05 ~) (81,250)

Total rewenue bonds ................................................................................. $ 1,548,269 $ 1,678,844 Finan cial R!eip omt

8. PAYMENTS IN LIEU OF TAXES:

The District is required to make payments in lieu of taxes, aggregating 5% of the gross revenue derived from electric retail sales within the city limits of incorporated cities and towns served directly by the District. Such payments totaled $10.1 million for each of the years ended December 31 , 2017 and 2016, respectively.

9. ASSET RETIREMENT OBLIGATIONS:

The District implemented GASB Statement No. 83, Certain Asset Retirement Obligations, in 2017, retroactive to 2016. Prior to the implementation of the GASB guidance, FASB guidance had been used for ARO reporting . The FASB guidance required measurement of the liability based on discounted dollars or the present value of the asset's disposal costs. Measurement under GASB guidance is based on the best estimate in today's dollars, or the current value, of cash outlays expected to be incurred in the future. The FASB guidance required the recognition of a corresponding capital asset whereas the GASB guidance requires the recognition of a corresponding deferred outflow of resources. The District uses regulatory accounting to align asset retirement costs with their related recognition in rates. The difference in the ARO amounts and the related deferred outflows represents the amounts collected in rates.

AROs as of December 31 , are as follows (in OOO's) :

Description 2017 2016 CNS license termination costs ... ..... .... .. .... ............ ........ ... .. .. ... ........ . $ 811 ,801 $ 795,026 GGS and SS ash landfiUs .. ....... ... ... ... ..... .. ... .. ..... ......... ... ........ ..... .. . . 9,040 3,208 Ains1110rth ...... ....... .... .................. ......... ... .............. .... ... ................. . 1,953 1,913 Underground storage tanks .... ..... ...... .. .. ... .. ...... .. ....... ....... .. ... .... ..... . 1 000 1 000

$ 8231794 $ 8011147 The District is required by the Nudear Regulatory Commission ("NRC") to decommission CNS after cessation of plant operations, consistent with regulations in the U.S. Code of Federal Regulations. The CNS license termination costs were based on an external study for costs for three different scenarios: 1) immediate commencement of decommissioning after license termination in 2034; 2) delayed decommissioning for 46 years after license termination; and 3) safe storage for 60 years after license termination. The costs were based on several key assumptions in areas of regulation, component characterization, high-level radioactive waste management, low-level radioactive waste disposal, performance uncertainties (contingency) and site restoration requirements. An expert panel, consisting of District management representatives with considerable nudear experience, assigned probabilities to these different scenarios. The costs in the study were in 2015 dollars. Rates in the consumer price index for all urban consumers r cPI-Ufl) were used to adjust these obligations for inflation.

The inflation rates used were 2.11 % and 2.07% for the years 2017 and 2016, respectively. The District has funds set aside for decommissioning of $600.9 million and $581 .8 million as of December 31 , 2017 and 2016, respectively. These funds exceeded the NRC's required funding provisions for nudear decommissioning.

The District is required by the Environmental Protection Agency r EPA.) and the Nebraska Department of Environment Quality r NDEQ*) to decommission the ash landfills at GGS and Sheldon, consistent with their regulations. As GASB guidance is undear related to the accounting treatment for ash landfill AROs, GASB Statement No. 83 was considered analogous authoritative literature and applied in this situation. The ash landfills have an estimated dosure date in the years 2086 and 2036 for GGS and Sheldon, respectively. The AROs were based on external studies to estimate oosts using one scenario after an assessment of the physical site. The dosure and post-0osure costs were based on the Closure Plan in the studies and *nduded final cover placements and lined surface water control structures. The costs in the latest studies were in 2017 dollars. The ARO increased from 2016 because of a regulatory change whidl increased the post-0os re period from five years to 30 years. The District provided guarantees and financial assurance through correspondence and supporting

ntonnation to NDEQ in 2017. Commencing in 2017, the District induded in rates decommission*ng costs for certain assets at GGS and Sheldon. The costs *nduded in rates for the decommissioning of the ash landfills were Finanoial !Report 46

$0.4 million for the year ended December 31 , 2017. These rate collections reduced the related deferred outflow for the ash landfills.

The District is required by contracts with the landowners of the Ainsworth site to restore the property, as nearly as possible, to the condition it was in prior to the District's use of the easement. Ainsworth has an estimated closure date of September 30, 2025. The ARO was based on an external study for costs using one scenario. The assumptions included: 1) no hazardous construction material abatement is required ; 2) no environmental costs to address site clean-up; 3) floor drain and septic tanks will be decommissioned per state regulations; 4) wind turbine nacelles, turbine towers, transformers and other electrical equipment are removed from the site by the demolition contractor; 5) the O&M buildings and one onsite meteorological tower were included with the demolition costs; 6) all foundations will be removed to two feet below finished grade; and 7) all concrete and crushed rock surfacing will be removed . The costs in the study are in 2015 dollars. Rates in the consumer price index for all urban consumers (" CPI-U") were used to adjust these obligations for inflation. The inflation rates used were 2.11% and 2.07% for the years 2017 and 2016, respectively. There are no legally required funding and assurance provisions associated with this ARO. The costs included in rates for the decommissioning of Ainsworth were $0.1 million for the year ended December 31 , 2017. These rate collections reduced the related deferred outflow for Ainsworth .

The District is required by the NDEQ to decommission the underground storage tanks at various locations in the District's service area, consistent with its regulations. The remaining lives of the storage tanks cannot be reasonably estimated. The AROs were based on the best estimate of District management representatives with expertise in environmental issues. The District provided guarantees and financial assurance through correspondence and supporting information to NDEQ in 2017. There have not been any decommissioning costs for the underground storage tanks included in rates.

Financial Rep)()rnt

The District continues to use regulatory accounting for AROs , so the amount included in rates is recorded as decommissioning expense. As a result, the impact on the District's 2016 financial statements was limited to the Balance Sheet. The changes made to the 2016 financial statements after the implementation of the GASB guidance were as follows (in OOO's) :

As originally As reported reported Balance Sheet 2016 2016 Change Utility Plant, at Cost:

Utility plant in sen,ke ... .. ............. .......... .... .. .. ...... ....... ... ...... .. .... ... . $ 4 ,835,829 $ 4,971 ,259 $(135,430)

Less reser\ for depreciation .............. ................... .... .. ......... ....... . 2,573,645 2,708 ,036 (134,391) 2,262,184 2,263,223 (1 ,039)

Construction work in progress ....... ............. .. ............. ....... .. .......... . 135,853 135,853 Nuclear fuel , at amortized cost ..... ... ........ ........ ....... ....... ....... ..... ... . 197,730 197,730

$ 2,595,767 $ 2,596,806 $ (1 ,039)

Other Long-Term Assets:

Regulatory asset for ARO ... ............. ......... ........... ..................... .. . . $ $ 44,899 $ (44,899)

Regulatory asset for other postemployment benefits ....... .... ........ .... . 221 ,973 221 ,973 Long-term capacity contracts .. ....... ........ ... ..... .... ..... .. ....... .. .. ........ . 159,445 159,445 Unamortized financing costs ..... ........ ................ ........... ................ . 8,945 8,945 lm.estment in The Energy Authority ................ ............. .. ...... ..... .... . 6,370 6,370 Other .... ........... ........... .. ............. ... ... ............. .. .......... ...... .... .. ..... . 9,416 9,416

$ 406,149 $ 451 ,048 $ (44,899)

Total Assets ... ... ......... ..... .. .............. .. ..... .................. ... ..... ........... . $ 4,560,252 $ 4,606,190 $ (45,938)

Deferred Outflows of Resources:

Asset retirement obigation .. ..... ......... ........................................... . $ 219,378 $ $ 219,378 lklamortized cost of refunded debt .... .......... ..... ....... ..... .............. ... 42,664 42,664 Other postemployment benefits ........ ............................... ............... . 82,289 82,289

$ 344,331 $ 124,953 $ 219,378 TOTAL ASSETS AND DEFERRED OUTFLO\NS $ 4,904,583 $ 4,731 , 143 $ 173,440 Other Long-Term Liabilities:

Asset retire,nent obligation .................................... ........ ................. . $ 801 ,147 $ 627,707 $173,440 Net olher fJC)Slen1>1oyment benefit liability ..................................... .. 258,609 258,609 Other ..... ....... .*............................ .......................*...*. ..*...........*. ... 3,362. 3,362.

$ 1,063,118 $ 889,678 $173,440 Tolal Liabilities ............................................................................ . $ 3,218,208 $ 3,044,768 $ 173,440 TOTAL LIABILITIES, DEFERRED ll'FLCJINS, ANl f£T POSITION ... $ 4,904,583 $ 4,731 ,143 $173,440 48

10. RETIREMENT PLAN:

The District's Employees' Retirement Plan (the "Plan") is a defined contribution 401 (k) pension plan established and administered by the District to provide benefits at retirement to regular full-time and part-time employees.

There were 1,848 and 1,931 active plan members as of December 31 , 2017 and 2016, respectively. Plan provisions and contribution requirements are established and may be amended by the Board.

Plan members are eligible to begin participation in the Plan immediately upon hire. Contributions ranging from 2%

to 5% of base pay are eligible for District matching dollars after six months of employment. The District contributes two times the Plan member's contribution based on covered salary up to $40,000. On covered salary greater than $40,000, the District contributes one times the Plan member's contribution. The Participants' contributions were $13.7 million and $13.4 million for 2017 and 2016, respectively. The District's matching contributions were $12.0 million and $12.3 million for 2017 and 2016, respectively. Total contributions of $1.3 and

$1.4 million were accrued in Accounts payable and accrued liabilities as of December 31 , 2017 and 2016 respectively. Beginning January 1, 2018, the Board approved an increase in matching for covered salary from

$40,000 to $75,000.

Plan members are immediately vested in their own contributions and earnings and become vested in the District's contributions and earnings based on the following vesting schedule:

Years of Vesting Participation Percent 5 years or more .. ...... .... .... .. ... ... .. ... .. ... . . 100%

4 years ..... ....... .. ...... ...... ... ..... .... .... ..... . 75%

3 years ..... .... .... ......... .... ... .... ..... ....... .. . 50%

2 years .... .. .. .... ........ .. ... ... ..... .. .... ...... .. . 25%

Less than 2 years ...................... ... ... ... . 0%

Nonvested District contributions are first used to cover Plan administrative expenses and any remaining forfeitures are allocated back to Plan participants.

Employees may also contribute to a defined contribution 457 pension plan r 457 Plan*). The 457 Plan is a tax-deferred investment option with no District match. Pay period contributions can be elected and changed at any time. Ear1y withdrawals can be made from the 457 Plan following separation of service regardless of age with no IRS penalty. Income taxes are owed on any withdrawals. The Participants' contributions were $2.5 million and

$2.1 million for 2017 and 2016, respectively.

11 . OTHER POSTEMPLOYMENT BENEFITS:

The District ear1y adopted the provisions of GASB Statement No. 75 r GASB 75m ). Accounting and Financial Reporting for Postemployment Benefits Other than Pensions, in 2016. There was no impact to beginning net position as a result of the implementation in 2016.

A. General information regarding the OPEB Plan -

Plan Desalption The District's Postemployment Medical and Life Benefits Plan r Plan") provides postemployment hospital-medical and life insurance benefits to qualifying retirees, surviving spouses, and employees on long-term disability and their dependents. Benefits and related eligibility, fund*ng and other Plan provisions, for this single-employer, defined benefit Plan, are authorized by the Board.

The Plan has been amended over the years and provides different benefits based on hire date and/or the age of lhe employee. The District pays a I or part of the cost (determined by age) of certain hospital-medical premiums for employees *red on or prior to December 31 , 1992. Employees hired on or after January 1, 1993, are subject to a oonbibution cap that limits the District's portion of the cost of such coverage to the full premium the year the employee reached age 65, or the year in which the employee retires if older than age 65. Employees hired on or after January 1, 1999, are no eligible for other postemployment hospital-medical benefits once they reach age Financial Rep0Iit

65. Employees hired on or after January 1, 2004, are not eligible for other postemployment hospital-medical benefits once they retire. The District amended the Plan effective July 1, 2007, to provide that any former employee who is rehired will receive credit for prior years of service. The District further amended the Plan effective September 1, 2007, to provide that employees hired or rehired on or after that date must work five consecutive years immediately prior to retirement to be eligible for other postemployment hospital-medical benefits once they retire. In May 2015, the Board approved a change for Medicare-eligible retirees for prescription drugs from the District's self-insured employee prescription plan to a group insured Medicare Part D supplement effective January 1, 2016. The District also provides a postemployment death benefit of $5,000 for qualifying employees.

Employees Covered by Benefit Terms The following table shows the employees covered by the hospital-medical benefit terms as of January 1:

2017 2016 Acti~ efll)loyees .. .... .. .... .. .... .............. ...... .... ................... ....... 1,007 1,175 lnacti~ efll)loyees in retirement status ..... ..... ....... .... ..... ........ .. . 1,381 1,260 lnacti~ efll)loyees in long-term disability status ....... ..... .... ... ...... 64 67 Total efll)loyees co~red by benefit terms .... ....... .. ..... ...... ......

2,452 2,502 The following table shows the employees covered by the life insurance benefit terms as of January 1:

2017 2016 Acti~ efll)loyees ...... .... ... ... ....... .... .. .... .... ... .. ... ..... .... ..... ......... 1,851 2,003 lnacti~ efll)loyees in retirement status .... ... .............. ..... ........ ... 1,213 1,077 lnacti~ efll)loyees in long-term disabifity status .. ... ... .. . .. .......... .. 72 74 Contributions Total efll)loyees co~red by benefit terms .... .. ...... ... .. .... .........

3,136 3,154 The Board annually approves the funding for the Plan, which has a minimum funding requirement of the actuarially-determined annual required contribution (" ARC") to achieve full funding status on or before December 31 , 2033. The District OPES contributions were $28.4 million and $74.7 million in 2017 and 2016, respectively. Certain wholesale customers under the 2002 Contracts have pursued legal action related to their objection of the indusion in rates of additional collections of previously incurred OPES costs. Since the arbitration filing in May 2016, collections from these customers have been held in separate accounts and have not been transferred to the Trust, pending the outcome of the legal action. The revenue collections for the catch-up OPES funding from these customers, which have not yet been transferred to the Plan, were $3.5 million and $1 .6 million as of December 31 , 2017 and 2016, respectively.

Contributions from inactive Plan members for their share of the premium payments are reported as a reduction of benefit expenses. Contributions from Plan members were $0.6 million and $0.5 million for 2017 and 2016, respectively.

B. Net OPEB Liability-The District's net OPES liability was measured as of January 1, 2017, and January 1, 2016, and the total OPES liability used to calculate the net OPEB liability was determined by an actuarial valuation as of these dates.

Finain:oia[ IR!epolit 50

Actuarial Assumptions The actuarial assumptions used in the January 1, 2017, valuation were based on the results of an actuarial experience study for the period January 1, 2016 through December 31 , 2016. The total OPEB liability in the January 1, 2017, actuarial valuation was determined using the following actuarial assumptions, applied to all periods included in the measurement, unless otherwise specified:

Actuarial cost method . . . . .. . . . .. . . . Entry Age Normal Amortization method ............... Level amortization of the unfunded accrued liability Amortization period ..... ... .... ... .. 16-year closed period Asset valuation method . . . . . . . . . .. . 5-year smoothed market Discount rate ...... .... ....... ......... 6.25%

Healthcare cost trend rates .. .... Pre-Medicare: 7.3% initial, ultimate 4.5%

Post-Medicare: 9.1% initial, ultimate 4.5%

Inflation .. ............ ...... ............. . 2.1%

Investment rate of return ......... . 6.25% , net of investment e,q:,ense, including inflation Mortality ************ **** **** ** *** ******** RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2016 INith generational projection Retirement age .... .................. . Varies by age The actuarial assumptions used in the January 1, 2016, valuation were based on the results of an actuarial experience study for the period January 1, 2015 through December 31 , 2015. The total OPEB liability in the January 1, 2016, actuarial valuation was determined using the following actuarial assumptions, applied to all periods included in the measurement, unless otherwise specified:

Actuarial cost method ...... ....... . Entry Age Normal Amortization method ..... .. ....... . le'.el amortization of the unfunded accrued liability Amortization period ............. ... . 17-year closed period Asset valuation method ........... . 5-year smoothed market Discount rate ............... .......... . 6.25%

Healhcare cost trend rates ..... . Pre-Medicare: 8% initial, ultimate 5%

Post-Medicare: 6. 75% initial, ultimate 5%

Inflation ............... .... .............. . 2.1%

lmestment rate of return ..... .... . 6.25%, net of in\eSlment e)(J)el"lse, including inflation Mlrtafily ................................ . RP-2014 Aggregate table projected back to 2006 using Scale '1.P-2014 and projected forward using Scale t.P-2015 with generational projection Retirement age ............. ... ...... . Varies by age The long-term expected rate of return on OPEB plan investments was determined using a building-block method in which best-estimate ranges of expected future rates of return (expected returns, net of OPEB plan investment expense and inflation} are developed for each major asset dass. These ranges are combined to produce the long-term expected rate of return by weighting the expected future real rates of return by the target asset allocation percentage and by adding expected inflation.

Finanoial Rel1l011t

The target allocation and best estimates of geometric real rates of return for each major asset class are summarized in the following table for the valuation measurement date of January 1,:

2017 Long-Term Expected Real Rate of Asset Class Target Allocation Return Equity (1) .. ... ......... . 70% 6.8%

Fixed Income ....... ... . 30% 3.6%

100% 6.1%

2016 Long-Term Expected Real Rate of Asset Class Target Allocation Return Equity (1) ...... ..... ... . 68% 6.8%

Fixed I ncorne ........ .. . 32% 3.5%

100% 6.1%

(1) The actuary included the 10% real estate allocation 'Nith equity.

Discount Rate The discount rate used to measure the total OPEB liability was 6.25% for the actuarial valuations as of January 1, 2017 and 2016. The projection of cash flows used to determine the discount rate assumed that contributions will be made at rates equal to the actuarially-determined contribution rates. Based on those assumptions, the OPEB Plan's fiduciary net position was projected to be available to make all projected benefit payments for current active and inactive employees. Therefore, the long-term expected rate of return on OPEB plan investments was applied to all periods of projected benefit payments to determine the total OPEB liability.

C. Changes in the Net OPEB Liability-The following table shows the Total OPES Liability, Plan Fiduciary Net Position and Net OPEB Liability as of January 1, 2017, and the changes during this period, based on the valuation measurement date of January 1, 2017 (in OOO's):

Liability Net Position Liability (a) (b) (a-b)

Balances at 1/1/2016 ....................... .... .. .... ...... .... ... .... .. .. ............. $ 333,833 $ 75,224 $ 258,609 Changes for the year: ........................ ........ .. ............ ..... ..................

~cecost .................................... ............ .... ........................... . 3 ,322 3,322 Interest ......................................................... .......................... . 20,658 20,658 Differences between expected and actual e>cperience ................. . (203) (203)

Changes of assurJl)tions ......................................... ... .............. . (1 8,807) (18,807)

Contributions - ~ e r .......................................................... . 74,712 (74,712)

Net inleSbnent income ................................................................ . 6 ,101 (6,101)

Benefit payments ********** ........................................................... . (13,459) (13,459)

Adrninislrati\e ellpeflSe .**..********** ***. ***.********..***...*****...*.. ***.. **...** (69) 69 Net changes ................................................................................. (8,489) 67,285 (75,774)

Balances at 1/1/2017 .................................................................... $ 325,344 $ 142,509 $ 182,835 Net position as a % d Tot:11 OPES Liabirity ..................................... 43.8%

Financial iR~pont 52

There were changes made in certain assumptions for the valuation measurement date of January 1, 2017. The mortality assumption was updated to the RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2016 with generational projection. The health care trend dates were also updated.

In December 2016, the District initiated a voluntary early retirement incentive program ("Program") to all regular, full-time employees, excluding senior management, who met certain retirement-eligible criteria. There were 121 employees who accepted the offer. The impact of the Program was included in the January 1, 2017 actuarial valuation.

Sensitivity of the Net OPES Liability to Changes in the Discount Rate The following table shows the net OPES liability of the District, as well as what the net OPES liability would be if it were calculated using a discount rate that is 1-percentage-point lower (5.25%) or 1-percentage-point higher (7.25%) than the discount rate (6.25%) at the measurement date of January 1, 2017 (in OOO's) :

1% Decrease Discount Rate 1% Increase Net OPES Liability . .. .. . .. .. .. .. .. $224,980 $182,835 $147,850 Sensitivity of the Net OPES Liability to Changes in the Healthcare Cost Trend Rates The following table shows the net OPES liability of the District, as well as what the net OPES liability would be if it were calculated using healthcare cost trend rates that are 1-percentage-point lower (Pre-Medicare ranging from 6.3% initial to 3.5% ultimate, Post-Medicare ranging from 8.1 % initial to 3.5% ultimate) or 1-percentage-point higher (Pre-Medicare ranging from 8.3% initial to 5.5% ultimate, Post-Medicare ranging from 10.1% initial to 5.5%

ultimate) than the healthcare cost trend rates (Pre-Medicare ranging from 7.3% initial to 4.5% ultimate, Post-Medicare ranging from 9.1 % initial to 4.5% ultimate) at the measurement date of January 1, 2017 (in OOO's):

Healthcare Cost 1% Decrease Trend Rates 1% Increase Net OPES Liability . .. .. .. . .. .. . . .. $148,629 $182,835 $223,946 The following table shows the Total OPES Liability, Plan Fiduciary Net Position and Net OPES Liability as of January 1, 2016, and the changes during this period, based on the valuation measurement date of January 1, 2016 (in OOO's):

Total OPEB Plan Fiduciary NetOPEB Liabiity Net Position Liability (a) (b) (a-b)

Balances at 1/1/2015 .................................................................. . $ 323,122 $ 64,487 $ 258,635 Changes for the year: ........ ...........................................................

Seniice cost ......... ................................................................... . 3,228 3,228 Interest .... ............. ................................................................... 19,877 19,877 Differences between ellpeeted and actual experience ................. . 13,657 13,657 Changes of assufll)lions .......................................................... . (9,149) (9,149)

Contributions - elJl)loyer .......................................................... . 28,242 (28,242)

Net investment income ............................................................. . (453) 453 Benefit payments ..................................................................... . (16,902) (16,902)

Administrative e>epenSe ***************** ****** ********************************* ****** (1 50) 150 Net changes ................................................................................ . 10,711 10,737 (26)

Balances at 1/1/2016 .................................................................. . $ 333,833 $ 75,224 $ 258,609 Net position as a % of Total OPEB Liability ..................................... 22.5%

Financial R!~p@nt

Sensitivity of the Net OPEB Liability to Changes in the Discount Rate The following table shows the net OPEB liability of the District, as well as what the net OPEB liability would be if it were calculated using a discount rate that is 1-percentage-point lower (5.25%) or 1-percentage-point higher (7.25%) than the discount rate (6.25%) at the measurement date of January 1, 2016 (i n OOO's):

1% Decrease Discount Rate 1% Increase Net OPEB Liability .. ... .... .. ..... $306,681 $258,609 $219,295 Sensitivity of the Net OPEB Liability to Changes in the Healthcare Cost Trend Rates The following table shows the net OPEB liability of the District, as well as what the net OPEB liability would be if it were calculated using healthcare cost trend rates that are 1-percentage-point lower (Pre-Medicare ranging from 7% initial to 4% ultimate, Post-Medicare ranging from 5.75% initial to 4% ultimate) or 1-percentage-point higher (Pre-Medicare ranging from 9% initial to 6% ultimate, Post-Medicare ranging from 7.75% initial to 6% ultimate) than the healthcare cost trend rates (Pre-Medicare ranging from 8% initial to 5% ultimate, Post-Medicare ranging from 6.75% initial to 5% ultimate) at the measurement date of January 1, 2016 (in OOO's):

Healthcare Cost 1% Decrease Trend Rates 1% Increase Net OPEB Liability. ..... .. ... .. .. . $219,672 $258,609 $306,151 OPEB Plan Fiduciary Net Position The following table shows information on the OPEB Plan Fiduciary Net Position as of December 31 , (in OOO's):

2017 2016 Assets:

Cash and cash equivalents .......... ..... ... ............. .... ............. .... ............... .. .. . $ 3,027 $ 9,609 Receivables:

Contributions .. ...... ..... .. .... ... ...... .... ......... ..... ... ... ..... .. ......................... .. . 149 53 ln~trnent income ............ ... .. .. ... .. ... .. ..... ...... ........ .... ... ................. ...... . 451 261 ln~ n t s .. ............. ... .. ........... ..... ........ .... ....... ................... ............... ... . 173,4 19 132,875 Total Assets ........ .............. ........... .. ............ ...... .. ..... ...... ................. . 177,046 142,798 Liabilities:

Payables:

Benefits - heallh care .............. ........................................... .................. 148 128 Benefits - life insurance ................. ..................................................... . 33 29 In~ e)9)el1Se ...................... .......... ............... ............................. . 51 85 Total liabilities ......... ............. .... ....................................................... 232 289 Net Position - Restricted for Other Postenl)loyment Benefils ............................. $176,814 $ 142,509 Finaliloial R~p0nt 54

The following tables show the OPEB assets that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31 , 2017 (in OOO 's) :

Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable Assets Inputs Inputs (Level 1) (Level 2) (Level 3) Total U.S. Treasury and government agency securities .. $ $ 15,956 $ $ 15,956 Corporate issues .. ... .. .. .. ....... ..... .. ... .. ................... 28,056 28,056 Foreign issues ... ....... .... ... .. .. ... .... .... ... ..... .. ... ..... . . 6,629 6,629 Municipal issues .. ... .. ...... .. .... ... ......... .... ......... ... ... 779 779 Domestic common stocks ..... .. .... .. ... .. .. ........ ....... . 45,678 45,678 Foreign stocks ...... ....... ...... ... ... .. ... .... .... .... .. ..... .. . 4,002 4,002 Mutual funds ......... ........ .. ..... ......................... ..... . 64,1 83 64,1 83

$ 113,863 $ 51 ,420 $ $ 165,283 Other investments measured at net asset value (A) . 8,1 36

$ 173,419 (A) The fair value of investments in a real estate fund has been estimated using the net asset value per share (or its equivalent) practical expedient and has not been classified in the fair value hierarchy. The fund allows for quarterly redemption with a 90-day notice. There are no unfunded commitments to the fund as of December 31 ,

2017.

The following tables show the OPES assets that are accounted for and reported at fair value on a recurring basis by level within the fair value hierarchy as of December 31 , 2016 (in OOO's) :

2016 Level 1 Le'vel 2 Le'vel 3 Total U.S. Treasury and government agency securities .. $ $ 2,678 $ 2,678 Corporate issues .... .............. ..... ...... ....... ............ . 18,162 18,162 Foreign issues ...... ..... ...... ................ .................. . 5,161 5,161 Municipal issues ............... ....... ...... ........ ............. . 766 766 Domestic conmon stocks .................... ............... . 39,002 39,002 Foreign stocks ....................... ............................. . 3,569 3,569 Mrtual funds ...................................................... . 63,537 63,537

$106,108 $ 26,767 $ $ 132,875 D. OPEB Expense, Deferred Outflows of Resources and Deferred Inflows of Resources Related to OPEB-The Board annually approves the OPEB expense in rates and has authorized the use of regulatory accounting to equate OPEB expense with the amount in rates. OPEB expense was $16.7 million for 2017, as calculated under the GASB 75 guidance. With regulatory accounting, OPEB expense and the amount induded in rates was $53.3 million for 2017. This amount induded a $25.0 milron catch-up rate collection for the net OPEB liability for past production-level services.

Fiinamoial R!eiprnrnt

The following table summarizes the reported deferred outflows and deferred inflows of resources as of December 31 , 2017 (in OOO's):

Deferred Outflow Deferred Inflow Difference between actual and expected experience $ 3,030 $ 16,475 Difference between expected and actual earnings on investments .... ....... . 3,283 Contributions made during the year ended December 31 , 2017 .... ..... ... .. . 28,290 Total Deferred Outflows ....... ...... .. ... ........ ... .. ..... .. .... ... ..... ..... ... ... ..... . $ 34,603 $ 16,475 The deferred outflows of resources related to the contributions made during the year ended December 31 , 2017 will be recognized in the actuarial valuation with a measurement date of January 1, 2018. The net of the other deferred outflows and deferred inflows of resources will be recognized as a reduction in OPEB expense as follows (in OOO's):

Year Amount 2018 ..... .... . $ (733) 2019 .. ... .... . (733) 2020 ... ... .... (734) 2021 ...... ... . (1 ,699) 2022 .. ........ (2,461) 2023 ..... ... .. (2,535) 2024 ... .. ... .. {1 ,267}

Total $!10, 162~

OPEB expense was $20.6 million for 2016, as calculated under the GASB 75 guidance. VVith regulatory accounting, OPEB expense and the amount included in rates was $52.9 million for 2016. This amount included a

$25 million catch-up rate collection for the net OPEB liability for past production-level services. There were no deferred inflows of resources related to OPEB as of December 31 , 2016. The following table summarizes the reported deferred outflows of resources as of December 31 , 2016 (in OOO's):

2016 Difference between actual and expected experience .......... ..... ..... ...... . $ 3,769 Difference between expected and actual earnings on imestments ... .. .. 3,862 Contributions made during the year ended December 31 , 2016.. ... ..... . 74,658 Total Deferred Outflows ... ... ... .. .. ........ .......... ... ... ... ............. ... ... .... . $ 82,289 The deferred outflows related to the contributions made during the year ended December 31 , 2016 were recognized in the actuarial valuation with a measurement date of January 1, 2017. The other deferred outflows of resources will be recognized in OPEB expense as follows (in OOO's):

Year Amount 2017 ...... $ 1,705 2018 ...... 1,704 2019 ....... 1,705 2020 ...... 1,704 2021 ...... 739 2022 ...... 74 Total $ 7,631 Additional information is available in the unaudited Required Supplementary lnfonnation section following the Notes to Financial Statements.

56

12. COMMITMENTS AND CONTINGENCIES:

A. Fuel Commitments -

The District has various coal supply contracts with minimum estimated future payments of $103.0 million at December 31 , 2017. These contracts expire at various times through the end of 2020. The coal transportation contract in place is sufficient to deliver coal to the generation facilities through and beyond the expiration date of the aforementioned contracts and is subject to price escalation adjustments.

The District has a contract for uranium purchases and deliveries in 2018, a contract for conversion services of uranium to uranium hexafluoride which is in effect through 2021 , a contract for enrichment services through 2024, if needed, and a contract for fabrication services through January 18, 2034 if needed, the end of the current operating license of CNS. These commitments for nuclear fuel material and services have combined estimated future payments of $233.0 million.

B. Power Purchase and Sales Agreements -

The District has entered into a participation power agreement (the "NC2 Agreement") with OPPD to purchase 23.7% of the power of NC2, estimated to be 157 MW of the power from the 664 MW coal-fired power plant constructed by OPPD. The NC2 Agreement contains a step-up provision obligating the District to pay a share of the cost of any deficit in funds for operating expenses, debt service, other costs, and reserves related to NC2 as a result of a defaulting power purchaser. The District's obligation pursuant to such step-up provision is limited to 160% of its original participation share (23.7%). No such default has occurred to date.

The District has entered into a participation power sales agreement with Municipal Energy Agency of Nebraska ("MEAN") for the sale to MEAN of the power and energy from Gerald Gentleman Station ("GGS") and CNS of 50 MW which began January 1, 2011 and continues through December 31 , 2023.

The District has entered into power sales agreements with LES for the sale to LES of 8% of the net power and energy of GGS. In return, LES agrees to pay 8% of all costs attributable to GGS. This agreement is to terminate upon the later of the last maturity of the debt attributable to the station or the date on which the District retires such station from commercial operation. The District had entered into a power sales agreement with LES for the sale to LES of 30% of the net power and energy of Sheldon. In return , LES agreed to pay 30% of all costs attributable to Sheldon. The District and LES executed a termination and release agreement in May 2017 for the Sheldon Station Participation Power Agreement with the termination effective December 31 ,2017.

The District has wholesale power purchase commitments with the Western Area Power Administration through 2020 with annual minimum future payments of approximately $36.3 million. These purchases are subject to rate changes.

The District owns and operates the 60 MW Ainsworth Wind Energy Facility and has 20-year participation power agreements to sell 28 MW to four other utilities. In addition, the District has power purchase agreements with seven wind facilities having a total capacity of 435 MW. These agreements are for terms ranging from 20 to 25 years and require the District to purchase all the electric power output of these wind facilities. 11le District has entered into power sales agreements to sell 154 MW of this capacity to four other utilities in Nebraska over similar terms.

The District has entered into a power purchase agreement with Central for the purchase of the net power and energy produced by the Kingsley Project during its operating life. The Kingsley Project is a hydroelectric generating unit at the Kingsley Dam in Keith County, Nebraska with an accredited net capacity of 37 MW.

The District has entered *nto long-term PRO Agreements having initial terms of 15, 20, or 25 years with 79 municipalities for the operation of certain retail electric distribution systems. These PRO Agreements expire on various years between 2023 and 2042. These PRO Agreements obligate the District to make payments based on gross revenues from the municipalities and pay fur normal property additions during the term of the agreement

C. Wholesale Power Contracts -

The District serves its wholesale customers under total requirements contracts that require them to purchase total demand and energy requirements from the District, subject to certain exceptions. In 2016, the District entered into 20-year VVholesale Power Contracts ("2016 Contracts") with 23 public power districts, one cooperative, and 37 municipalities. One public power district and 9 municipalities are served under 2002 VVholesale Power Contracts ("2002 Contracts"), which expire on December 31 , 2021 .

The 2016 Contracts allow a wholesale customer to give notice to reduce its purchase of demand and energy requirements from the District based on a comparison of the District's average annual wholesale power costs in a given year compared to power costs of U.S. utilities for such year listed in the National Rural Utilities Cooperative Finance Corporation Key Ratio Trend Analysis (Ratio 88) (the "CFC Data"). The CFC Data places a utility's power costs in percentiles so that any given utility can compare its power costs on a percentile basis to the CFC published quartile information. The 2016 Contracts allow a wholesale customer to reduce its demand and energy purchases from the District if the District's average annual wholesale power costs percentile level for a given year is higher than the 45th percentile level (the "Performance Standard Percentile") of the power costs of U.S. utilities for such year as listed in the CFC Data. The 2016 Contracts would not allow any reductions in demand and energy purchases by a wholesale customer as long as the District's average annual wholesale power costs percentile remained below the Performance Standard Percentile.

The following table lists the District's wholesale power costs percentile for the calendar years 2012 to 2016 set forth in the CFC Data:

CFC Data Year Percentile 2012 29.1%

2013 31.0%

2014 27.6%

2015 31.3%

2016 28.2%

The District has ten wholesale customers remaming on the 2002 Contracts. The 2002 Contracts allow a wholesale customer to reduce its purchases of demand and energy upon giving appropriate notice. Reductions could amount to as much as 90% of their demand and energy requirements under certain circumstances. All wholesale customers under the 2002 wholesale contracts are required to purchase at least 10% of their demand and energy from the District through December 31, 2021.

The District has received notices from all wholesale customers under the 2002 Contracts as to their intent to level off, reduce, or terminate the requirements for various amounts from 2017 through 2021. The ten customers ind ude one municipality which has a short-term wholesale contract which terminated in May 201 6 . These wholesale customers represented 4.8% and 4.5% of operating revenues for 2017 and 201 6, respectively. The District expects that no requirements of said wholesale customers will be served by the District in 2022, and such wholesale customers will purchase all of their electric requirements from other suppliers. The District expects to seU the energy not sold to such wholesale customers into the SPP Integrated Market and continues to explore additional firm requirement and/or fixed price agreements.

In 2016, three of the District's municipal wholesale customers began purchasing power from three of the Dismcfs public power district wholesale customers. These customers represented 0.1% of the District's 2016 operating revenues. One of the District's municipal wholesale customers allowed their contract to terminate. This customer represented less than 0.1 % of the District's 2016 operating revenues.

The 2016 wholesa: e rates resulted in a 0.6 % inaease for wholesale customers who signed the 2016 Contracts, and a 3.8% increase for those wholesale customers who remained under the 2002 Contracts. Customers under the 2002 Contracts will pay their share of previously *ncurred OPEB costs (or the catch-up amount) through rates prior to the expiration of their contracts *n 2021 . Customers under the 2016 Conbacts received a discount for lhe deferral of OPEB collections, extending those collections

to the new contract period and resulting -n the lower Fi:nancia[ :Report 58

net wholesale rate increase. The District financed with taxable debt the 2016 Contracts customers' share of the OPEB catch-up amount for 2016 and 2017 and plans to issue additional taxable debt for catch-up funding in 2018. The customers under the 2016 Contracts will commence payment of the related debt service beginning in 2022 , the year after the expiration of the 2002 Contracts.

Eight of the ten wholesale customers who remained under the 2002 Contracts filed for binding arbitration in May 2016 claiming the 2016 wholesale rate violates the 2002 Contracts, is contrary to Nebraska's rate statute and reflects bad faith toward those not signing the 2016 Contracts. These customers have since added the OPEB component of the 2017 wholesale rate to their dispute. The arbitration panel ruled in favor of the District in April 2017. This case was appealed and argued before the Nebraska State Supreme Court ("Court") in March 2018.

The District is awaiting the Court decision. Since the arbitration filing in May 2016 , disputed amounts have been set aside in separate accounts. The amount of disputed revenues in the separate accounts was $2.5 million and

$0.9 million as of December 31 , 2017 and 2016, respectively.

The Northeast Nebraska Public Power District filed a lawsuit in the District Court of Wayne County, Nebraska regarding the demand and energy reduction provisions under the 2002 Contract. The court issued an order dated February 26, 2016, in favor of the Northeast Nebraska Public Power District which allows them to reduce their demand and energy purchases from the District by 30% in 2018, 60% in 2019 and 90% in 2020. The court decision will apply to certain other customers who have given notice for demand and energy reductions under the 2002 Contract. On March 23, 2016, the District filed a notice of appeal. The Nebraska Court of Appeals affirmed the District Court decision in June 2017. The Nebraska Supreme Court declined to review the matter in September 2017.

D. SPP Membership and Transmission Agreements -

The District is a member of SPP, a regional transmission organization based in Little Rock, Arkansas.

Membership in SPP provides the District reliability coordination service, generation reserve sharing, regional tariff administration, induding generation interconnection service, network, and point-to-point transmission service, and regional transmission expansion planning. The District was able to participate in SPP's energy imbalance market, a real-time balancing market that provides members the opportunity to have SPP dispatch resources based on marginal cost, through February 2014. On March 1, 2014, SPP commenced a Day-Ahead, Ancillary Services, and Real-nme Balancing Market Integrated Market. The Integrated Market also provides a financial market to hedge unplanned transmission congestion , or financial virtual products to hedge uncertainties, such as unplanned outages.

The District entered into a Transmission Facilities Construction Agreement effective June 15, 2009, with TransCanada Keystone Pipeline, LP ("Keystone* ). This agreement addresses the transmission facilities, construction, cost allocation , payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone to the District's transmission system. Cost of the project was

$8.4 million and repayment by Keystone, over a 10-year period, began in June 2010 with a remaining balance due the District of $2.6 million and $3.5 million as of December 31 , 2017 and 2016, respectively.

The District entered into a second Transmission Facilities Construction Agreement effective July 17, 2009, with TransCanada Keystone XL Pipeline, LP r Keystone XL.). This agreement addresses the transmission facilities, construction, cost allocation, payment, and applicable cost recovery for the interconnection and delivery facilities required for the interconnection of Keystone XL to the District's transmission system. TransCanada Corporation and TransCanada Pipeline USA Ltd. have jointly and severally guaranteed the payment obligations of Keystone under its agreements with the District. The agreement was cancelled in 2016 after the 2012 application for a Presidential permit for construction of the Keystone XL Pipeline was denied. All outstanding balances for Keystone XL were paid in 2016.

E. Cooper Nuclear Station-On November 29, 2010, the NRC formally issued a certificate to the O"strict to commemorate the renewal of the operating license for CNS ror an additional 20 years until January 18, 2034. CNS entered the 20-year period of extended operation on January 18, 2014.

Fim:aJ11cial IR~p0rt

In October 2003 , the District entered into an agreement (the "Entergy Agreement") for support services at CNS with Entergy Nuclear Nebraska, LLC ("Entergy"), a wholly owned indirect subsidiary of Entergy Corporation. In 2010, the Entergy Agreement was amended and extended by the parties until January 18, 2029, subject to either party's right to terminate without cause by providing notice and paying a $20 million termination charge. The Entergy Agreement requires the District to reimburse Entergy's cost of providing services, and to pay Entergy annual management fees. These annual management fees were $18.5 million for 2017 and $18.5 million for year 2016. These fees will increase by an additional $1 .0 million in 2019, and by an additional $3.0 million in 2024.

Entergy is eligible to earn additional incentive fees in an amount not to exceed $4.0 million annually if CNS achieves identified safety and regulatory performance targets. Entergy has achieved certain safety and regulatory performance targets during the term of the Entergy Agreement and has been eligible for at least a portion of this annual incentive fee.

Since the earthquake and tsunami of March 11 , 2011 , that impacted the Fukushima Dai-ichi Plants in Japan, the District, as well as the rest of the nuclear industry, has been working to first understand the events that damaged the reactors and associated fuel storage pools and then look to any changes that might be necessary at the United States nuclear plants. Of particular interest is the performance of the General Electric ("GE") boiling water reactor with Mark 1 containment systems in Japan and their on-site used fuel storage facilities. CNS utilizes this same containment system; however, significant enhancements to the design have been made over the life of the plant.

An NRC Near Term Task Force Review of Insights from the Fukushima Dai-ichi Accident was published on July 12, 2011 that included 12 recommendations for improvements for U.S. reactors. Subsequent to that report, on October 18, 2011 , the NRC approved seven of the Task Force recommendations for implementation.

On March 12, 2012 , the NRC issued three orders to the U.S. nuclear industry as a result of the Fukushima Dai-ichi event in Japan. The first order requires all domestic nuclear plants to better protect supplemental safety equipment and obtain additional equipment as necessary to protect the reactor in the event of beyond design basis external events. The second order requires nuclear plant operators of boiling water reactors like CNS to modify reactor licenses with regard to reliable hardened containment wetwell vents. The third order requires nuclear plant operators to add reliable spent fuel pool water level instrumentation. The NRC has also issued a request for information pertaining to re-evaluation of seismic and flooding hazards, and a communications and staffing assessment for emergency preparedness.

Phase one and phase three of said order have been completed. Phase two of said order, which requires a drywell vent or a basis and strategy for why venting the drywell would not be required, will be completed by the condusion of the fall 2018 refueling and maintenance outage.

Since the initial site-specific seismic reevaluation analysis for CNS that resulted in no identified seismic-related modifications to CNS, the District has performed an additional seismic analysis and has worked to answer additional questions from the NRG on this topic. The NRC has determined that CNS will have to perform the High Frequency Evaluation and a Spent Fuel Pool Evaluation, but will not have to complete a Seismic Probabilistic Risk Assessment. Unknown to the District at this time is the extent of modifications that may be required as a result of these additional seismic reevaluations.

The District continues to work with the U.S. Army Corps of Engineers and the NRC to validate the data necessary to complete the CNS flood hazard reevaluation. The District submitted its updated flooding analysis to the NRC *n February 2015. The NRC subsequently submitted questions to which the District has responded and submittal of the updated flood hazard reevaluation was completed *n September 2016. Based on current interim, and long-term strategies for flooding mitigation, it is not expected that any modifications will be required as a result of the flood hazard reevaluations. All equipment and materials required to mitigate the *dentified impacts associated with the flood hazard reevaluation have been purchased and the equipment required has been installed. Additional equipment purchased, but not required to be *nsta1led un ess an issue occurs, is stored on-site in dedicated storage facilities.

The District's cost estimate for plant modifications associated with the NRC's Fukushima Dai-ichi related orders *s currentty estimated to cost $23.3 million, wh. ch is expected to be funded primarily rrom the revenues of the District and from the proceeds of General Revenue Bonds. As of December 31 , 2017, $17.3 mi lion has been spent on Fin.anoial Repo11t 60

plant modifications with an additional $6.0 million expected to be spent to establish compliance with the Fukushima Dai-ichi orders.

CNS substantially completed the construction of a dry cask used fuel storage project in December 2009 to support plant operations until 2034, which is the end of the Operating License. The first loading campaign was completed in January 2011 and encompassed the loading of 488 used fuel assemblies from the CNS used fuel pool into eight dry used fuel storage casks for on-site storage. A second loading campaign , encompassing the loading of 610 used fuel assemblies into ten dry used fuel storage casks, began in April 2014 and was completed in June 2014. The third loading campaign , encompassing the loading of 732 used fuel assemblies into 12 dry used fuel storage casks, began in June 2017 and was completed in November 2017.

As part of various disputed matters between GE and the District, GE has agreed to continue to store at the Morri s Facility the spent nuclear fuel assemblies from the first two full core loadings at CNS at no additional cost to the District until the expiration of the current NRC license in May 2022 for the Morris Facility. After that date, storage would continue to be at no cost to the District as long as GE can maintain the NRC license for the Morris Facility on essentially the existing design and operating configuration.

As a result of the failure of the DOE to dispose of spent nuclear fuel from CNS as required by contract, the District commenced legal action against the DOE on March 2, 2001. The initial settlement agreement addressed future claims through 2013. On January 13, 2014, the District and the DOE agreed to extend the settlement agreement through 2016. On March 2, 2017, the District and the DOE agreed to extend the settlement agreement through 2019. The District has received $118.2 million from the DOE for damages from 2009 through 2016. The District also reserves the right to pursue future damages through the contract claims process. A corresponding regulatory liability for these DOE receipts was established in Other deferred inflows of resources. The District plans to use the funds to pay for costs related to CNS. The balance in the regulatory liability was $66.2 million and $82.7 million as of December 31, 2017 and 2016, respectively.

Under the tenns of the DOE contracts, the District was also subject to a one mill per kilowatt-hour ("k\Nh") fee on all energy generated and sold by CNS which was paid on a quarter1y basis to DOE. The District includes a component in its wholesale and retail rates for the purpose of funding the costs associated with nudear fuel disposal. V\lhile the District expects that the revenues developed therefrom will be sufficient to cover the District's responsibility for costs currently outlined in the Nuclear Waste Policy Act, the District can give no assurance that such revenues will be sufficient to cover all costs associated with the disposal of used nudear fuel. On May 9, 2014, the DOE provided notice that they would adjust the spent fuel disposal fee to zero mills per kV\lh effective May 16, 2014. Correspondingly, no additional payments have been made to the DOE for fuel disposal since that date. The Board authorized the continued collection of this fee at the same rate. This approach ensures costs are recognized in the appropriate period with current customers receiving the benefits from CNS paying the appropriate costs. The expense for spent nudear fuel disposal is recorded based on net electricity generated and sold and the regulatory liability will be eliminated when payments are made for spent nudear fuel disposal.

Under the provisions of the Federal Price Anderson Act, the District and all other licensed nudear power plant operators could each be assessed for d aims in amounts up to $127.3 million per unit owned in the event of any nudear incident involving any licensed facility in the nation, with a maximum assessment of $19.0 million per year per incident per unit owned.

The NRC evaluates nudear plant performance as part of its reactor oversight process r RoP~). The NRC has five performance categories induded in the ROP Action Matrix Summary that is part of this process. As of December 31 , 2017, CNS was in the Licensee Response Column, which is the first or best of the five NRC defined performance categories and has been in this column since the first quarter of 2012.

Refueling and maintenance outages are required to be performed at CNS approximately every two years. The most recent refueling and maintenance outage began on September 25, 2016 and was completed on November 8, 2016. During this outage, in addition to replacing 184 fuel assemblies and conducting routine maintenance, equipment replacements induded one of the two reactor water recirculation pump impellers and motor, the startup station transformer and the high pressure turbine.

Financial IR!ep>ID11t

Significant operations and maintenance expenses are incurred in the outage year. The Board authorized the collection of these costs over a multi-year period to levelize revenue requirements for expenses and help ensure the customers receiving the benefits from CNS are paying the costs, commencing in 2017. The regulatory liability for the pre-collection of outage costs was $20.0 million as of December 31 , 2017 and will be eliminated through revenue recognition during the 2018 outage year.

F. Environmental -

Water The Federal Clean Water Act contains requirements with respect to effluent limitations relating to the discharge of any pollutant and to the environmental impact of cooling water intake structures. The NDEQ establishes the requirements for the District's compliance with the Clean Water Act through issuance of National Pollutant Discharge Elimination System permits. NDEQ issued the District permits for the following facilities: GGS, Sheldon , CNS, Beatrice Power Station, Canaday Station, Kearney Hydro and the North Platte Office Building. The District anticipates some level of fish protection equipment technology installation, both for impingement and entrainment, may be necessary for CNS and only for impingement at GGS. Until the final compliance options are determined, the District does not know the financial impact of this regulation.

On January 2, 2016, the final Steam Electric Power Plant Effluent Guidelines rule (the "Effluent Rule") became effective. The Effluent Rule revises the technology-based effluent limitation guidelines and standards that would strengthen the existing controls on discharges from steam electric power plants and sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. Generally, the Effluent Rule establishes new or additional requirements for wastewater streams from the following processes and byproducts associated with steam electric power generation: flue gas desulfurization, fly ash, bottom ash, flue gas mercury control , and gasification of fuels such as coal and petroleum coke. VVhile the District facilities subject to the Effluent Rule are CNS, GGS, Sheldon and Canaday Station, the Effluent Rule only has an impact on Sheldon.

Sheldon will be required to be a zero discharge facility for bottom ash transport water by December 31 , 2023. The District is currently analyzing the options for compliance, which is estimated to cost $2.4 million. EPA has listed this rule as one they will consider for regulatory reform and the requirements may be subject to change.

Acid Rain Program The Clean Air Act Amendments Title IV established a regulatory program, known as the Acid Rain Program , to address the effects of acid rain and impose restrictions on sulfur dioxide ("S02") and nitrogen oxides ("NOx")

emissions. Acid Rain Permits have been issued for the following facilities: GGS, Sheldon, Canaday Station and Beatrice Power Station. The Acid Rain Permits allow for the discharge of S02 at each facility pursuant to an allowance system. The District expects to have sufficient allowances for its generating facilities through 2023, but may be required to purchase additional allowances in the Mure.

Mercury and Air Toxic Standards On February 16, 2012, the EPA issued a final rule intended to reduce emissions of toxic air pollutants from power plants. Specifically, the Mercury and Air Toxics Standards ("MATS") Rule will require reductions in emissions from new and existing coal- and oil-fired steam utility electric generating units of toxic air pollutants. The affected District facilities, which are GGS and Sheldon, are in compliance with the MATS Rule.

Cross-State Air Pollution Rule The EPA issued a rule in 2012 which is referred to as the Cross-State Air Pollution Rule r cSAPR") that would require significant reductions in S02 and NOx emissions in a number of states, induding Nebraska. CSAPR compliance periods went into effect on January 1, 2015. Based on the current CSAPR allocation methodology and current generation projections through 2023, the District expects to have sufficient CSAPR allowances to cover affected facilities emission requirements over that timeframe, but may be required to purchase additional allowances in the future.

Regional Haze The EPA issued final regulations for a Regional Haze Program *n J ne 1999. The purpose oflhe regulations is to

mprove visibility in the form of reduci g reg*ona1 haze *n 156 national parks and wi demess areas across the country. Haze is formed, *n part, from emissions of S02and o...

EinaNoi~l Repc1rnt 62

For phase one of the Regional Haze rule the Best Available Retrofit Technology ("BART") Report was submitted to the NDEQ in August 2007 and a revised report was submitted in February 2008. The BART Report proposed that the Best Available Retrofit Technology to meet regional haze requirements at GGS would be low NOx burners on Units No. 1 and No. 2 and no additional controls for S02. Low NOx burners have now been installed on both units at GGS. The NDEQ State Implementation Plan ("SIP") agreed with the BART Report. The NDEQ submitted the SIP to the EPA for approval on June 30, 2011 .

On May 30, 2012, the EPA issued a rule pertaining to the Regional Haze Program that would approve the trading program in CSAPR as an alternative to determining BART for power plants. As a result, states in the CSAPR region may substitute the trading program in CSAPR for source-specific BART for S02 and/or NOx emissions as specified by CSAPR.

On July 6, 2012, the EPA issued the final rule on the Nebraska Regional Haze SIP. The final rule approved the GGS NOx portion of the SIP but disapproved the S02 portion of the SIP for GGS. The EPA issued a Federal Implementation Plan ("FIP") for GGS which stated that BART for S02 control at GGS is compliance with CSAPR.

The District is currently in compliance with all requirements of phase one of the Regional Haze rule.

On January 10, 2017, the EPA issued final changes to the Regional Haze regulations for the second planning phase of the Regional Haze Rule. The District is evaluating the proposed changes but will not know the full impact to the District until the State and the EPA begin implementing the second phase of the Regional Haze rule. The State is required to submit their SIP for the second phase of the Regional Haze rule by July 31 , 2021 .

Clean Air Act Compliance (New Source Review)

As part of EPA's nationwide investigation and enforcement program for coal-fired power plants' compliance with the Clean Air Act induding new source review requirements, on December 4, 2002, the Region 7 office of the EPA began an investigation to determine the Clean Air Act compliance status of GGS and Sheldon. The District timely responded to EPA's requests for information. By letter dated December 8, 2008, EPA Region 7 sent a Notice of Violation ("NOV") to the District which alleges that the District violated the Clean Air Act by undertaking five projects at GGS from 1991 through 2001 without obtaining the necessary permits. In February and August 2009, District representatives met with federal government representatives to discuss the NOV and no additional meetings have been scheduled. In general, enforcement action by EPA against the District for alleged noncompliance with Clean Air Act requirements, if upheld after court review, can result in the requirement to install expensive air pollution control equipment that is the BART and the imposition of monetary penalties ranging from $25,000 to $32,500 per day for each violation. The District cannot determine at this time whether it will have any Mure financial obligation with respect to the NOV.

On July 22, 2016, EPA Region 7 sent a new 114(a) request for documents and information regarding the compliance status of GGS. On December 27, 2016, EPA Region 7 sent a 114{a} follow-up request for additional information on certain projects that were identified in the July 22, 2016, 114{a) request The EPA is reviewing whether there have been physical or operational changes since November 8, 2007 which resulted in, or could result in, increased emissions induding projects undeJWay or planned for the next two years. The District gathered documents and information and provided it to the EPA. Failure to comply with the Clean Air Act can result in fines as described above and/or requirements to install additional emission control equipment. The District believes GGS has been operated and maintained in compliance with the requirements of the Clean Air Act.

Clean Power Plan On October 23, 2015, the EPA published the final Clean Power Plan r cPP~) rule addressing carbon dioxide reductions from existing fossil-fueled power plants. The final rule gave states significant responsibility for determining how to achieve the reduction targets through the development of a State Plan. Each state was given a reduction target to be achieved by 2030, with interim reductions required between 2022 and 2029. The Nebraska reduction target for 2030 was 40% below 2012 emissions. On February 9, 2016, the U.S. Supreme Court issued a stay for the CPP until all legal challenges have been decided. The O.C. Cira.iit Court of Appeals heard oral arguments on September 27, 2016 and a decision was expected in early 2017. Prior to the Court

ssuing a decision, the EPA asked the Court to hold the legal process *n abeya oe wtf e the EPA worked to repeal and replace the CPP.

Financial R~J!>Olit

On October 16, 2017, the EPA published a proposed rule to repeal the CPP on the basis that the CPP exceeded the authority of the EPA. Comments are due on April 26, 2018. On December 28, 2017, the EPA published an Advanced Notice of Proposed Rulemaking ("ANPR") seeking input on what a CPP replacement rule should include. Comments on the ANPR were due on February 26, 2018. Due to the stay and the EPA process to repeal and replace the CPP with a new rule, the NDEQ and the District have halted all work on implementing the CPP. It is unknown at this time what the potential impact to the District will be until the EPA finalizes the CPP replacement rule.

Impact from Changes to Environmental Regulatory Requirements Any changes in the environmental regulatory requirements imposed by federal or state law which are applicable to the District's generating stations could result in increased capital and operating costs being incurred by the District. The District is unable to predict whether any changes will be made to current environmental regulatory requirements, if such changes will be applicable to the District and the costs thereof to the District.

G. Sale of Spencer Hydro Facility-In September 2015, a memorandum of understanding ("MOU") was signed for the sale of the District's Spencer Hydro ("Spencer") facility, including dam , structures, land, water appropriations, and perpetual easements for the reservoir, to the Niobrara River Basin Alliance ("Alliance") (Five Natural Resource Districts) and the Nebraska Game and Parks Commission ("NGPC") for $12.0 million. The 2015 MOU that was signed expired on June 1, 2017 . Following the expiration, both parties have negotiated an agreement for the sale and purchase of the Spencer facility. It was distributed to the Alliance and NGPC in December 2017 for signatures. Currently, there is no agreement in place.

13. LITIGATION:

On January 1, 2016, Tri-State Generation and Transmission Association , Inc. ("Tri-State") became a transmission member of SPP and its transmission facilities in western Nebraska, and the corresponding annual transmission revenue requirements were placed under the SPP tariff. SPP filed at FERC to place the Tri-State transmission facilities in the District's pricing zone rather than establish a new pricing zone for Tri-State. The District protested the filing at FERC, because it results in approximately a $4.3 million per year, or 8% , cost shift increase to the transmission customers in the District's pricing zone. As a result of the District's protest, FERC set the matter for hearing before an administrative law judge and the District and other parties submitted briefs and testimony on the proper pricing zone and whether SPP's decision is discriminatory and an unjust and unreasonable cost shift to the District. On February 23, 2017, the administrative law judge issued an initial decision upholding the SPP pricing zone placement and made recommended condusions to FERC. This initial decision has no legal effect until reviewed and acted upon by FERC which will be after the District submits briefs on its exception to the factual and legal condusions in the initial decision. FERC's future ruling on the initial decision can be appealed to a federal circuit court of appeals. When FERC will rule on the initial decision cannot be predicted.

Information on litigation with wholesale customers under the 2002 Contracts is induded in Note 12.C.

A number of daims and suits are pending against the District for alleged damages to persons and property and for other alleged liabilities arising out of matters usually incidental to the operation of a utility, such as the District.

In the opinion of management, based upon the advice of its General Counsel, the aggregate amounts recoverable from the District, taking into account estimated amounts provided in the financial statements and insurance coverage, are not material as of December 31 , 2017 and 2016.

14. SUBSEQUENT EVENTS:

In 2017, the Nebraska Department of Revenue r NDORj conducted a sales and use tax audit on the District's records for the audit period of June 1, 2014 through May 31 , 2017. NOOR issued a Notice of Deficiency Determination r 0etenninationj to the District for approximately $6.5 million, induding interest and penalties of over $1 .0 mi lion, on January 30, 2018. Beyond the minor sales and use tax corrections contained *n a nonnal audit Determination, the NOOR assessed a most $5.5 m

lion of tax on the payments to municipalities under PRO Agreements. The 0-strict disagrees with the DOR's assessment and filed a Petition for Redetemfoation lo formally challenge the Determination on Mardi 29. 2018.

Fina:noial Report 64

SUPPLEMENTAL SCHEDULES (UNAUDITED)

Calculation of Debt Service Ratios in accordance 'Nith the General Revenue Bond Resolution for the years ended December 31 , (in OOO's) 2017 2016 Operating revenues .. .. ........ ....... .... .. ... ...... .......... .............. ..... ... ..... ...... .. .... ..... . $ 1,101 ,642 $ 1,153,997 Operating expenses ... ................ ...... ........ .... ...... .... ................ ...... ......... ... ..... . . (988,931) (1,040,715)

Operating income ....... ......... ... ....... ....... .. .......... ..... ..... .. .. ... ..... ... ....... ......... . 112,711 113,282 Investment and other income .. ... ....... ...... .. ... ....... .... ... .. ... ... .. ...... ..... ... ......... .. .. . 23,591 31 ,772 Debt and other expenses ....... .. .. ....... .... ............. .... ..... .... .. .. ... .. ... .. ........... .. .. ... . (64,986) (62,121 )

Increase in net position .... ......... ........ ...... .............. .... ... .... .. ..... ...... ... ...... ... . 71 ,316 82,933 Add:

Debt and related expenses(1) .. ... .... ...... ......... ..... .... ... ... ..... ........ .... .... ...... ... . . 64,986 62,121 2

Depreciation and amortizationc i ... ...... .. .. ...... ... ........ .. .. .. ... .. ............... ......... . 122,559 133,666 Payments to retail communitiesC3J . ** . . *. . ***. . . *. . *.* .. * *. .*. * *******. . ********* * *** . ** * * * * **** *

27, 102 26,553 4

Amortization of current portion of financed nuclear fuelc i ...... ... ... ... ........... ... . 42 ,198 39 ,468 Amounts colected from third party financing arrangementscsi .... ................... . 938 991 257,783 262,799 Deduct Investment income retained in construction fundscsi .... .. ...... ..... ...... ....... .. ..... . 645 354 Unrealized (loss) gain on investment securities ....... .. ... ..... ... ....... .... .... .... ..... . (2 ,595) 43 (1,950) 397 Net position available for debt sen,ke for the General Revenue Bond Resolution .. $ 331 ,049 $ 345,335 Amounts deposited in the General System Debt Sen,ke Account Principal .... ..... .... ........ ......... ............. ..... ....... .... .................... .... .... ....... ..... . $ 84,125 $ 101,135 Interest .......... .. ........... .,... ... ... ........ .............. .... ... .... ..... ...... ....... ........... ..... . . 71 , 198 72,959

$ 155,323 $ 174,094 Ratio of net position available for debt service to debt seniice deposits .... .... ....... . 2. 13 1.98 (1) Debt and other expenses, exdusive of interest on customer deposits, is not an operating expense as defined in the Resolution.

(2) Depreciation and amortiza tion are not operating expenses as defined in the Resolution.

(3) Under lhe provisions of the Resolution, lhe payments required to be made by the District with respect to the Professional Retail Operating Agreements are to be made on the same basis as subordinated debt (4) General Revenue Bond financed nuclear fuel is not an operating expense as defined in the Resolution. As of July 31, 2015, the effective date of the T axa.ble Revolving Oedit Agreement, amortization of nuclear fuel expense under lhe TRCA is excluded from the debt service calaJlalion as the District's obligation to m ake payments under the TRCA is subordinate to the District's obligation to pay debt service on General Revenue Bonds.

(5) The payments received by the District rrom third party financing arrangements are included as Revenues under the Resolution, but are not recognized as revenue under GAAP.

(6) Interest inoome on investments held in oonstruc:lion funds is not Revenue as defined in the Resolution.

Fi:nanoi~l Report

Schedule of Changes in the Net OPEB Liability and Related Ratios using a January 1 Measurement Date (in OOO's)

Total OPEB Liability 2017 2016 Ser...;ce Cost .................... .. ..................................... .. ... ... ........ ... .. ... ........ ... .... .... .. ............. .. $ 3,322 $ 3,229 Interest ...... ...... ..... ....... ....... ... ... ..... ..... ......... ......... .. ... .. .... .............. ..... ........... ....... .... ...... ... . 20,658 19,876 Differences Betv.een Expected and Actual Experiences.. ... ........ ..... .. ... .. ... .... ... .... .... ... .. ........ . . (203) 13,657 Changes of Assumptions ...... ..... .. .............. .... ....... .... .. .. ........... ..... ..... ........... ............... .. .. .... . (18,807) (9,149)

Benefit Payments ..... .... ... ... .... ................... ..... ... .. .. .. .... .. .. ..... .... ... .............................. .......... . (13,459} (16,902}

Net Change in Total OPES Liability ............................................... ...... ..... .... .. ........ .. ............ .. (8,489) 10,711 Total OPES Liability (beginning) .................. ........................ ..... .... .. ....... .. .. ... ..... .. .. .......... .... .. 333,833 323,122 Total OPEB Liability (ending) (a) .............................. ............ .... ........ ......... .. ....... .................. . $325,344 $333,833 Plan Fiduciary Net Position Contributions c,i .. .... .... .................. .. ...... ....... ... ........ .... ......... ... ... ........ ....... ................ ... ....... . $ 74,711 $ 28,242 Net lnl.strnent Income........ .......... ... ..... ...... ........... ..... .. .. .... ...... .............. ... ......... .... .. ...... ... . . 6,102 (453)

Benefit Payments c,i ......... ................ ......... ......... .. .. ........ ......... ... .. ... ....... .... ... ... .... ... .......... .. . (13,459) (16,902)

Administratil. Expense..... .......... .. ..... ..... ........... ..... ................... ....... ....... .... .. ... ... ... .... ......... . (69} (150}

Net Change in Plan Fiduciary Net Position ....................... ............... ...... ... .. ... ..... .... .. .. .......... .. 67,285 10,737 Plan Fiduciary Net Position (Beginning) ... .. ................... ... .... ... ..... ..... .................................... . 75,224 64,487 Plan Fiduciary Net Position (Ending) (b) ..................... .. .. ........... .... ....... .. .... ....................... ... . $142,509 $ 75,224 Net OPES Liability (Ending) (a) - (b) ........... ... ......... .......... ..... .... .. ..... ....... ............. ......... .. .... . $182,835 $258,609 Net Position as a % of Total OPES Liabitity .... ..... ... ... .... .. .... .... ... .......... .............. ...... ...... ... .. .. . 43.8% 22.5%

(1) Contributions are employer-only contributions. Inactil. member contributions v..ere netted wth benefit payments.

GASB Statement No. 75, Financial Reporting for Postemployment Benefit Plans Other Than Pension Plans, was implemented by the District in 2016. The provisions of this Statement were not applied to prior periods, as it was not practical to do so as the information was not readily available. The OPEB schedules are intended to show information for ten years. Additional years will be displayed when available.

Finanoial Rep <lmt 66

Schedule of OPEB Contributions for Years Ended December 31 , (in OOO's) 2017 2016 Actuarially Determined Contribution ....... ..... .............. ... .. ... .... ........ ..................... $ 21 ,006 $ 28,283 Contributions Made in Relation to the Actuarially Determined Contribution .... ..... .. . 28,439 74,711 Contribution Deficiency (Excess) ... ..... .. .. .... .... ......... ........... ...... ....... ..... ....... ..... . $ (7,433) $ (46,428)

Notes to Schedule:

Valuation date - Actuarially determined contribution rates are calculated as of January 1, one year prior to the end of the fiscal year in which contributions are reported .

Methods and assumptions used for 2017 -

Actuarial cost method . .. . . .. . . . . . .. Entry Age Normal Amortization method .. . . . .. .. . .. . . . Level amortization of the unfunded accrued liability Amortization period . . . . . . . .. . . . . .. .. 16-year closed period Asset valuation method . . . .. . . . . . .. 5-year smoothed market Discount rate . .. .. . . . . .. .. . .. . .. . . . . .. . 6.25%

Healthcare cost trend rates . .. ... Pre-Medicare: 7.3% initial, ultimate 4.5%

Post-Medicare: 9.1% initial, ultimate 4 .5%

Inflation ....... ... ..... .... ....... .... ... . 2.1%

Investment rate of return .... .. ... . 6.25%, net of investment e>q:>ense, including inflation Mortality** **************** *************** RP-2014 Aggregate table projected back to 2006 using Scale MP-2014 and projected forward using Scale MP-2016 with generational projection Retirement age ...... .......... ...... . Varies by age Methods and assumptions used for 2016-Actuarial cost method . . .. .. . ... . .. . Entry Age Normal Amortization method . .. .. .. .. .. . . .. Lei.el amortization of the unfunded accrued fiability Amortization period ... .............. 17-year closed period Asset valuation method ... ......... 5-year smoothed market Discount rate .... . . .. .. .. . ........ ... .. 6.25%

Healthcare cost trend rates . . .. . . Pre-Medicare: 8% initial, ultimate 5%

Post-Medicare: 6.75% initial, ulimate 5%

Inflation ............ ......... ............. 2.1%

lm.estment rate of return . .... .. .. . 6.25%, net of im.estment ellpeflse, including inflation Mortaity . ...... .. .. .. .. . ... ... . .. .. .. ... . RP-2014 Aggregate table projected back to 2006 using Scale Ml-2014 and projected fOMard using Scale f&>-2015 wth generational projection Retirement age . . ............. ..... .. . Varies by age Schedule of Investment Returns for Years Ended December 31 ,

2017 2016 Annual Money-Weighted Rate of Return, Net oflmestment Expense ............... . 14.2% 5.8%

GASB Statement No. 75, Financial Reporting for Postemployment Benefit Plans Other Than Pension Plans, was implemented by the District in 2016. The provisions of this Statement were not applied to prior periods, as it was not practical to do so as the information was not readily available. The OPEB schedules are intended to show information for ten years. Additional years will be displayed when available.

iFiNaincial Repent L

Vision Mission 76 049

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